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Washington, D.C. 20549
UNDER
THE SECURITIES ACT OF 1933
Delaware (State or other jurisdiction of incorporation or organization) | 1311 (Primary Standard Industrial Classification Code Number) | 90-0726667 (IRS Employer Identification Number) |
Houston, Texas 77010
(713) 579-5700
(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)
President, Chief Executive Officer and Chairman
Memorial Production Partners GP LLC
1401 McKinney, Suite 1025
Houston, Texas 77010
(713) 579-5700
(Name, address, including zip code, and telephone number, including area code, of agent for service)
John Goodgame Akin Gump Strauss Hauer & Feld LLP 1111 Louisiana Street, 44th Floor Houston, Texas 77002 (713) 220-8144 | Douglas E. McWilliams Jeffery K. Malonson Vinson & Elkins L.L.P. 1001 Fannin, Suite 2500 Houston, Texas 77002 (713) 758-2222 |
Large accelerated filer o | Accelerated filer o | Non-accelerated filer þ | Smaller reporting company o |
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The information in this preliminary prospectus is not complete and may be changed. These securities may not be sold until the registration statement filed with the Securities and Exchange Commission is effective. This preliminary prospectus is not an offer to sell nor does it seek an offer to buy these securities in any jurisdiction where the offer or sale is not permitted. |
• | We may not have sufficient cash flow from operations to pay the minimum quarterly distribution on our common units following the establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates. | |
• | We would not have generated sufficient available cash on a pro forma basis to have paid the minimum quarterly distribution on all of our units for the twelve months ended June 30, 2011. | |
• | Our estimated oil and natural gas reserves will naturally decline over time, and we may be unable to sustain distributions at the level of our minimum quarterly distribution. | |
• | Oil and natural gas prices are very volatile and a decline in oil or natural gas prices could cause us to reduce our distributions or cease paying distributions altogether. | |
• | Our general partner and its affiliates will own a controlling interest in us and will have conflicts of interest with, and owe limited fiduciary duties to, us, which may permit them to favor their own interests to the detriment of our unitholders. | |
• | Memorial Resource, the Funds and other affiliates of our general partner will not be limited in their ability to compete with us. | |
• | Neither we nor our general partner have any employees and we will rely solely on the employees of Memorial Resource to manage our business. The management team of Memorial Resource, which includes the individuals who will manage us, will also perform substantially similar services for itself and will own and operate its own assets, and thus will not be solely focused on our business. | |
• | Our unitholders have limited voting rights and are not entitled to elect our general partner or its board of directors. | |
• | Our unitholders will experience immediate and substantial dilution of $ per unit. | |
• | Our tax treatment depends on our status as a partnership for federal income tax purposes. | |
• | Our unitholders will be required to pay taxes on their share of our income even if they do not receive any cash distributions from us. |
Per Common Unit | Total | |||||||
Public offering price | $ | $ | ||||||
Underwriting discount(1) | $ | $ | ||||||
Proceeds, before expenses, to Memorial Production Partners LP | $ | $ |
(1) | Excludes a structuring fee equal to % of the gross proceeds of this offering payable to Citigroup Global Markets Inc. |
Citigroup | Raymond James | Wells Fargo Securities |
Barclays Capital | J.P. Morgan | RBC Capital Markets |
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EX-23.9 |
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• | “Memorial Production Partners,” “the partnership,” “we,” “our,” “us” or like terms refer collectively to Memorial Production Partners LP and its subsidiaries; | |
• | “our general partner” refers to Memorial Production Partners GP LLC, our general partner; |
• | “our predecessor” refers collectively to (a) BlueStone Natural Resources Holdings, LLC and its wholly-owned subsidiaries, (b) certain oil and natural gas properties owned by Classic Hydrocarbons Holdings, L.P., and (c) for periods after April 8, 2011, certain oil and natural gas properties owned by WHT Energy Partners LLC, a subsidiary of Memorial Resource that acquired those properties in April 2011, which are collectively our predecessor for accounting purposes and the owners, prior to the formation transactions, of the Partnership Properties; |
• | “the Funds” refers collectively to Natural Gas Partners VIII, L.P., Natural Gas Partners IX, L.P. and NGP IX Offshore Holdings, L.P.; | |
• | “Memorial Resource” refers collectively to Memorial Resource Development LLC and its subsidiaries; | |
• | “Partnership Properties” or “our properties” refers to the properties, producing wells, and related oil and natural gas interests to be contributed to us by our predecessor and certain other subsidiaries of Memorial Resource in connection with this offering; |
• | “formation transactions” refers to (i) the contribution by the Funds of their respective controlling ownership interests in certain of their subsidiaries (including our predecessor) to Memorial Resource prior to the closing of this offering and (ii) the contribution by Memorial Resource to us of the Partnership Properties (including the contribution to us of Columbus Energy, LLC, a wholly-owned subsidiary of BlueStone Natural Resources Holdings, LLC, and ETX I LLC, a wholly-owned subsidiary of WHT Energy Partners LLC, each of which owns certain of the Partnership Properties) at the closing of this offering, in each case including transactions related thereto, which are described on page 7; and |
• | “our management,” “our employees,” or similar terms refer to the management or other personnel of our general partner or, as applicable, provided to us or our general partner by Memorial Resource under an omnibus agreement among us, our general partner and Memorial Resource. |
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Estimated Pro Forma | Average Net Pro | Average | ||||||||||||||||||||||||||||||
Net Proved Reserves | Forma Production | Reserve-to- | Producing | |||||||||||||||||||||||||||||
% Natural | % Proved | Production | Wells | |||||||||||||||||||||||||||||
Bcfe | Gas | Developed | MMcfe/d | % | Ratio(1) | Gross | Net | |||||||||||||||||||||||||
(Years) | ||||||||||||||||||||||||||||||||
South Texas | 172.2 | 98 | % | 87 | % | 32 | 61 | % | 15 | 563 | 424 | |||||||||||||||||||||
East Texas | 152.5 | 76 | % | 76 | % | 20 | 39 | % | 21 | 727 | 185 | |||||||||||||||||||||
Total | 324.7 | 88 | % | 81 | % | 52 | 100 | % | 17 | 1,290 | 609 | |||||||||||||||||||||
(1) | The averagereserve-to-production ratio is calculated by dividing estimated pro forma net proved reserves as of December 31, 2010 by average pro forma net production for the year ended December 31, 2010. |
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Estimated Pro Forma | Average | |||||||||||||||||||||||||||||||
Net Proved Reserves(1) | Average Net Pro | Reserve-to- | Producing | |||||||||||||||||||||||||||||
% Proved | Forma Production | Production | Wells | |||||||||||||||||||||||||||||
Bcfe | % Natural Gas | Developed | MMcfe/d | % | Ratio(2) | Gross | Net | |||||||||||||||||||||||||
(Years) | ||||||||||||||||||||||||||||||||
East Texas(3) | 760.6 | 84% | 30% | 43 | 64% | 48 | 1,067 | 306 | ||||||||||||||||||||||||
North Louisiana | 224.7 | 73% | 44% | 18 | 27% | 35 | 267 | 172 | ||||||||||||||||||||||||
Rockies | 51.0 | 67% | 41% | 6 | 9% | 25 | 123 | 85 | ||||||||||||||||||||||||
Total | 1,036.3 | 81% | 34% | 67 | 100% | 43 | 1,457 | 563 | ||||||||||||||||||||||||
(1) | Memorial Resource’s estimated pro forma net proved reserves are (i) based primarily on reserve reports prepared by third-party independent petroleum engineers and (ii) exclusive of our estimated pro forma net proved reserves. | |
(2) | The averagereserve-to-production ratio is calculated by dividing estimated pro forma net proved reserves as of December 31, 2010 by average pro forma net production for the year ended December 31, 2010. | |
(3) | Includes properties in which we have a joint interest. Memorial Resource’s portion of these properties included 169 Bcfe of reserves as of December 31, 2010 and 20 MMcfe/d of average net pro forma production for the year ended December 31, 2010 associated with properties acquired by WHT Energy |
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Partners LLC in April 2011. Please read “— Our Partnership Structure and Formation Transactions — Background Information Regarding Our Predecessor and the Partnership Properties.” |
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• | Maintain and grow a stable production profile through accretive acquisitions and low-risk development; | |
• | Strategically utilize our relationship with Memorial Resource, the Funds, and their respective affiliates (including NGP) to gain access to and, from time to time, acquire producing oil and natural gas properties that meet our acquisition criteria; | |
• | Leverage our relationships with Memorial Resource, the Funds, and their respective affiliates (including NGP) to participate in acquisitions of third party producing properties and to increase the size and scope of our potential third-party acquisition targets; | |
• | Exploit opportunities on our current properties and manage our operating costs and capital expenditures; | |
• | Reduce exposure to commodity price risk and stabilize cash flows through a disciplined commodity hedging policy; and | |
• | Maintain reasonable levels of indebtedness to permit us to opportunistically finance acquisitions. |
• | Our long-lived reserves with significant production history and predictable production decline rates; | |
• | Our relationships with Memorial Resource, the Funds, and their respective affiliates (including NGP), which we believe will provide us with access to a portfolio of additional oil and natural gas properties that meet our acquisition criteria; | |
• | Our management team’s extensive experience in the acquisition, development and integration of oil and natural gas assets; | |
• | Our relationship with Memorial Resource, which provides us with extensive technical expertise in and familiarity with developing and operating oil and natural gas assets within our core focus areas; | |
• | Our relationships with Memorial Resource, the Funds, and their respective affiliates (including NGP), which we believe will help us with access to and in the evaluation and execution of future acquisitions; | |
• | Our diverse distribution of reserve value, with 1,290 gross (609 net) producing wells as of December 31, 2010, none of which contains estimated proved reserves in excess of 2% of our total estimated proved reserves as of December 31, 2010; | |
• | Our inventory of 345 proved low-risk infill drilling, recompletion and development opportunities in our core operational areas; and | |
• | Our competitive cost of capital and financial flexibility. |
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• | We may not have sufficient cash to pay the minimum quarterly distribution on our common units, following the establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates. | |
• | We would not have generated sufficient available cash on a pro forma basis to have paid the minimum quarterly distribution on all of our units for the twelve months ended June 30, 2011. | |
• | Our estimated oil and natural gas reserves will naturally decline over time, and it is unlikely that we will be able to sustain distributions at the level of our minimum quarterly distribution without making accretive acquisitions or substantial capital expenditures that maintain our asset base. | |
• | Oil and natural gas prices are very volatile, and a decline in oil or natural gas prices will cause a decline in our cash flow from operations, which could cause us to reduce our distributions or cease paying distributions altogether. |
• | Our general partner and its affiliates will own a controlling interest in us and will have conflicts of interest with, and owe limited fiduciary duties to, us, which may permit them to favor their own interests to the detriment of our unitholders. | |
• | Memorial Resource, the Funds and other affiliates of our general partner will not be limited in their ability to compete with us, which could cause conflicts of interest and limit our ability to acquire additional assets or businesses. | |
• | Neither we nor our general partner have any employees and we will rely solely on the employees of Memorial Resource to manage our business. The management team of Memorial Resource, which includes the individuals who will manage us, will also perform substantially similar services for itself and will own and operate its own assets, and thus will not be solely focused on our business. | |
• | Our predecessor has material weaknesses in its internal control over financial reporting. If we fail to establish and maintain effective internal control over financial reporting, our ability to accurately report our financial results could be adversely affected. | |
• | Our unitholders have limited voting rights and are not entitled to elect our general partner or its board of directors. Memorial Resource, as the owner of our general partner, will have the power to appoint and remove our general partner’s directors. | |
• | Our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights, without the approval of the conflicts committee of the board of directors of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations. | |
• | Control of our general partner and its incentive distribution rights may be transferred to a third party without unitholder consent. | |
• | We may issue an unlimited number of additional units, including units that are senior to the common units, without unitholder approval, which would dilute unitholders’ ownership interests. |
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• | Even if our unitholders are dissatisfied, they cannot remove our general partner without Memorial Resource’s consent. |
• | Our tax treatment depends on our status as a partnership for federal income tax purposes. If the Internal Revenue Service, or the IRS, were to treat us as a corporation for federal income tax purposes, then our cash available for distribution to our unitholders would be substantially reduced. | |
• | Our unitholders will be required to pay taxes on their share of our income even if they do not receive any cash distributions from us. |
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• | The Funds will contribute their respective controlling ownership interests in certain of their subsidiaries (including our predecessor) to Memorial Resource; and |
• | Memorial Resource will issue membership interests to the Funds reflecting an aggregate 100% membership interest in itself; and |
• | Memorial Resource will cause certain of its subsidiaries, including our predecessor, to contribute to us (i) a 100% membership interest in Columbus Energy, LLC, which owns certain oil and natural gas properties, (ii) a 100% membership interest in ETX I LLC, which owns certain oil and natural gas properties, (iii) specified oil and natural gas properties, which we refer to collectively with the properties owned by Columbus Energy, LLC and ETX I LLC as the “Partnership Properties,” and (iv) commodity derivative contracts for the three months ending December 31, 2011 and the years ending December 31, 2012, 2013, 2014, and 2015, which, together with the commodity derivative contracts to which Columbus Energy, LLC and ETX I LLC are party, cover approximately 77%, 75%, 69%, 14% and 8%, respectively, of our estimated production from our total proved developed producing reserves existing as of December 31, 2010, based on our reserve reports; |
• | We will issue to Memorial Resource common units and subordinated units, representing an aggregate % limited partner interest in us; | |
• | We will issue to our general partner general partner units, representing a 0.1% general partner interest in us, and all of our incentive distribution rights, which will entitle our general partner to increasing percentages of the cash we distribute in excess of $ per unit per quarter; | |
• | Our general partner will issue an aggregate 50% non-voting membership interest in itself to the Funds that will entitle the Funds to 50% of any cash distributions or common units received by our general partner in respect of our incentive distribution rights; | |
• | We expect to receive net proceeds of approximately $ million from the issuance and sale of common units to the public (based on the midpoint of the price range set forth on the cover page of this prospectus), representing a % limited partner interest in us, and we will use the net proceeds as described in “Use of Proceeds”; |
• | We expect to borrow approximately $130.0 million under a new $ million revolving credit facility, and we will use the proceeds as described in “Use of Proceeds”; and |
• | We and our general partner will enter into an omnibus agreement with Memorial Resource, pursuant to which, among other things, Memorial Resource will provide us and our general partner with management, administrative and operating services. |
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Ownership | ||||||||
Units | Interest | |||||||
Common units held by the public | % | |||||||
Common units held by Memorial Resource | % | |||||||
Subordinated units held by Memorial Resource | % | |||||||
General partner units | 0.1 | % | ||||||
Total | 100.0 | % | ||||||
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• | purchases and sales of oil and natural gas properties and other acquisitions and dispositions, including whether to pursue acquisitions that are also suitable for Memorial Resource, the Funds or their affiliates; | |
• | the manner in which our business is operated; | |
• | the level of our borrowings; | |
• | the amount, nature and timing of our capital expenditures; and | |
• | the amount of cash reserves necessary or appropriate to satisfy our general and administrative expenses, other expenses and debt service requirements, and to otherwise provide for the proper conduct of our business. |
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Common units offered hereby | common units or common units if the underwriters exercise in full their option to purchase additional common units. | |
Units outstanding after this offering | common units and subordinated units, representing % and %, respectively, limited partner interests in us ( common units and subordinated units, representing % and %, respectively, limited partner interests in us if the underwriters exercise in full their option to purchase additional common units). The general partner will own general partner units, or general partner units if the underwriters exercise their option to purchase additional common units in full, in each case representing a 0.1% general partner interest in us. | |
Use of proceeds | We intend to use the estimated net proceeds of approximately $ million from this offering, based upon the assumed initial public offering price of $ per common unit (the midpoint of the price range set forth on the cover of this prospectus), after deducting underwriting discounts, structuring fees and expenses, together with borrowings of approximately $130.0 million under our new revolving credit facility, to purchase the Partnership Properties from Memorial Resource and to pay fees and expenses associated with this offering and our formation transactions. We will use any net proceeds from the exercise of the underwriters’ option to purchase additional common units to repay additional indebtedness under our new revolving credit facility. Please read “Use of Proceeds.” | |
Cash distributions | We expect to make a minimum quarterly distribution of $ per unit per quarter on all common, subordinated and general partner units ($ per unit on an annualized basis) to the extent we have sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates. We refer to this cash as “available cash,” and it is defined in our partnership agreement included in this prospectus as Appendix A. Our ability to pay the minimum quarterly distribution is subject to various restrictions and other factors described in more detail under the caption “Our Cash Distribution Policy and Restrictions on Distributions.” For the first quarter that we are publicly traded, we will pay our unitholders a prorated distribution covering the period from the completion of this offering through , 2011, based on the actual length of that period. | |
Assuming our general partner maintains its 0.1% general partner interest in us, our partnership agreement requires us to distribute all of our available cash each quarter in the following manner during the subordinated period: | ||
• first, 99.9% to the holders of common units and 0.1% to our general partner, until each common unit has received the minimum quarterly distribution of $ plus any arrearages from prior quarters; |
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• second, 99.9% to the holders of subordinated units and 0.1% to our general partner, until each subordinated unit has received the minimum quarterly distribution of $ ; and | ||
• third, 99.9% to all unitholders, pro rata, and 0.1% to our general partner, until each unit has received a distribution of $ . | ||
If cash distributions to our unitholders exceed $ per common and subordinated unit in any quarter, our general partner will receive, in addition to distributions on its general partner interest, increasing percentages, up to 24.9%, of the cash we distribute in excess of that amount. We refer to these distributions as “incentive distributions.” Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions.” | ||
At the closing of this offering, the Funds will hold non-voting membership interests in our general partner that will entitle them to collectively receive 50% of any cash distributions made or common units issued to our general partner in respect of our incentive distribution rights. All other interests in our general partner will be owned by Memorial Resource. Please read “Certain Relationships and Related Party Transactions — Amended and Restated Limited Liability Company Agreement of Memorial Production Partners GP LLC.” | ||
Our ability to pay the minimum quarterly distribution is subject to various restrictions and other factors described in more detail in “Our Cash Distribution Policy and Restrictions on Distributions.” | ||
Pro forma cash available for distribution generated during the year ended December 31, 2010 was approximately $47.3 million, which would have been sufficient to allow us to pay the full minimum quarterly distribution on our common units, general partner units and subordinated units during that period (assuming the underwriters exercise in full their option to purchase additional common units). | ||
Pro forma cash available for distribution during the twelve months ended June 30, 2011 was approximately $39.1 million, which would have been sufficient to allow us to pay the full minimum quarterly distribution on our common units and general partner units and a quarterly distribution of $ on our subordinated units, or a quarterly distribution of $ on our subordinated units assuming the underwriters exercise in full their option to purchase additional common units, during that period. | ||
We have not calculated available cash on a pro formaquarter-by-quarter basis for the year ended December 31, 2010 or the twelve months ended June 30, 2011 to determine if we would have generated available cash sufficient to pay the minimum quarterly distribution for each individual quarter during those periods. For a calculation of our ability to have made distributions to our unitholders based on our pro forma results of operations for the year ended December 31, 2010 and the twelve months ended June 30, 2011, please read “Our Cash Distribution Policy and Restrictions on Distributions.” |
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The amount of available cash we need to pay the minimum quarterly distribution for four quarters on our common units, general partner units and subordinated units to be outstanding immediately after this offering is approximately $ million (or an average of approximately $ million per quarter). Please read “Our Cash Distribution Policy and Restrictions on Distributions.” | ||
We believe, based on our financial forecast and related assumptions included in “Our Cash Distribution Policy and Restrictions on Distributions — Estimated Adjusted EBITDA for the Twelve Months Ending September 30, 2012,” that we will have sufficient available cash to pay the aggregate minimum quarterly distribution of $ million on all of our common units, general partner units and subordinated units for the twelve months ending September 30, 2012. However, we do not have a legal obligation to pay distributions at our minimum quarterly distribution rate or at any other rate except as provided in our partnership agreement, and there is no guarantee that we will make quarterly cash distributions to our unitholders. Please read “Our Cash Distribution Policy and Restrictions on Distributions.” | ||
Subordinated units | Memorial Resource will initially own all of our subordinated units. The principal difference between our common units and subordinated units is that, in any quarter during the subordination period, the subordinated units are entitled to receive the minimum quarterly distribution only after the common units have received their minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Accordingly, holders of subordinated units may receive a smaller distribution than holders of common units or no distribution at all. Subordinated units will not accrue arrearages. |
The subordination period will begin on the closing date of this offering and will extend until the first business day on or after , 2014 that we have earned and paid from operating surplus, in the aggregate, distributions on each outstanding common unit, subordinated unit and general partner unit and any other partnership interests that are senior or equal in right of distribution to the subordinated units equaling or exceeding the minimum quarterly distribution payable with respect to a period of twelve consecutive quarters immediately preceding such date, provided there are no arrearages in the minimum quarterly distribution on our common units at that time. |
The subordination period will also end if our general partner is removed other than for cause, provided that units held by our general partner and its affiliates are not voted in favor of such removal. |
When the subordination period ends, all subordinated units will convert into common units on aone-for-one basis and all common units thereafter will no longer be entitled to arrearages. |
Early conversion of subordinated units | If we have earned and paid from operating surplus at least $ (125% of the minimum quarterly distribution) for four consecutive |
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quarters ending on or after , 2012 on each outstanding common unit, subordinated unit, general partner unit and any other partnership interest that is senior or equal in right of distribution to the subordinated units, in respect of any quarter ending on or after , 2012, in each case in respect of such four quarter period, all of the outstanding subordinated units will convert into common units. |
Issuance of additional units | We can issue an unlimited number of additional units, including units that are senior to the common units in right of distributions, liquidation and voting, on terms and conditions determined by our general partner, without the approval of our unitholders. Please read “Units Eligible for Future Sale” and “The Partnership Agreement — Issuance of Additional Securities.” | |
Limited voting rights | Our general partner will manage us and operate our business. Unlike stockholders of a corporation, our unitholders will have only limited voting rights on matters affecting our business. Our unitholders will have no right to elect our general partner or its directors on an annual or other continuing basis. Our general partner may not be removed except by a vote of the holders of at least 662/3% of the outstanding common and subordinated units, including any units owned by our general partner and its affiliates, voting together as a single class. Upon consummation of this offering, Memorial Resource and its affiliates will own an aggregate of approximately % of our outstanding common and subordinated units (or % of our outstanding common and subordinated units if the underwriters exercise their option to purchase additional common units in full) and will therefore be able to prevent the removal of our general partner. Please read “The Partnership Agreement — Limited Voting Rights.” | |
Limited call right | If at any time our general partner and its affiliates own more than 80% of the outstanding common units, our general partner has the right, but not the obligation, to purchase all of the remaining common units at a purchase price not less than the then-current market price of the common units, as calculated pursuant to the terms of our partnership agreement. Upon the consummation of this offering, Memorial Resource will own approximately % of our outstanding common units (or % of our outstanding common units if the underwriters exercise their option to purchase additional common units in full) and 100% of our subordinated units. Please read “The Partnership Agreement — Limited Call Right.” | |
Estimated ratio of taxable income to distributions | We estimate that if our unitholders own the common units purchased in this offering through the record date for distributions for the period ending , such unitholders will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be less than % of the cash distributed to such unitholders with respect to that period. Please read “Material Tax Consequences — Tax Consequences of Unit Ownership — Ratio of Taxable Income to Distributions” for information regarding the bases for this estimate. |
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Material tax consequences | For a discussion of other material federal income tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States, please read “Material Tax Consequences.” |
Directed unit program | At our request, the underwriters have reserved up to % of the common units being offered by this prospectus for sale at the initial public offering price to officers and directors of our general partner. For further information regarding our directed unit program, please read “Underwriting.” |
Agreement to be bound by the partnership agreement | By purchasing a common unit, you will be admitted as a unitholder of our partnership and will be deemed to have agreed to be bound by all of the terms of our partnership agreement. | |
Listing and trading symbol | We have applied to list our common units on the NASDAQ Global Market under the symbol “MEMP.” |
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• | adjustments to reflect the acquisitions of oil and natural gas properties consummated in June 2010, April 2011, and May 2011 by our predecessor; |
• | the contribution by Memorial Resource and certain of its subsidiaries, including our predecessor, to us of the Partnership Properties in exchange for common units, subordinated units and $ million in cash (based on the midpoint of the price range set forth on the cover page of this prospectus) and the issuance to our general partner of general partner units, representing a 0.1% general partner interest in us, and all of our incentive distribution rights; |
• | the issuance and sale by us to the public of common units in this offering and the application of the net proceeds as described in “Use of Proceeds”; and |
• | our borrowing of approximately $130.0 million under our new $ million revolving credit facility and the application of the net proceeds as described in “Use of Proceeds.” |
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Memorial Production | ||||||||||||||||||||||||||||
Partners LP | ||||||||||||||||||||||||||||
Our Predecessor | Pro Forma | |||||||||||||||||||||||||||
Six | ||||||||||||||||||||||||||||
Months | ||||||||||||||||||||||||||||
Six Months Ended | Year Ended | Ended | ||||||||||||||||||||||||||
Year Ended December 31, | June 30, | December 31, | June 30, | |||||||||||||||||||||||||
2008 | 2009 | 2010 | 2010 | 2011 | 2010 | 2011 | ||||||||||||||||||||||
(Unaudited) | (Unaudited) | |||||||||||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||||||
Statement of Operations Data: | ||||||||||||||||||||||||||||
Revenues: | ||||||||||||||||||||||||||||
Oil and natural gas sales | $ | 49,313 | $ | 24,541 | $ | 37,308 | $ | 14,813 | $ | 31,973 | $ | 87,762 | $ | 43,902 | ||||||||||||||
Other income | 622 | 319 | 1,433 | 1,314 | 252 | 1,404 | 244 | |||||||||||||||||||||
Total revenues | 49,935 | 24,860 | 38,741 | 16,127 | 32,225 | 89,166 | 44,146 | |||||||||||||||||||||
Costs and expenses: | ||||||||||||||||||||||||||||
Lease operating | 8,843 | 11,207 | 13,974 | 5,205 | 11,116 | 23,052 | 12,893 | |||||||||||||||||||||
Exploration | 374 | 2,690 | 39 | — | 56 | 36 | — | |||||||||||||||||||||
Production taxes | 3,127 | 1,464 | 2,112 | 967 | 2,084 | 7,387 | 3,525 | |||||||||||||||||||||
Depreciation, depletion and amortization | 12,353 | 15,226 | 20,066 | 8,173 | 10,759 | 34,772 | 14,577 | |||||||||||||||||||||
Impairment of proved oil and natural gas properties | 14,166 | 3,480 | 11,800 | 3,319 | 2,893 | 9,509 | — | |||||||||||||||||||||
General and administrative | 3,835 | 4,811 | 6,116 | 2,271 | 3,604 | 5,819 | 3,479 | |||||||||||||||||||||
Accretion | 224 | 320 | 663 | 251 | 466 | 1,072 | 534 | |||||||||||||||||||||
Gain on derivative instruments | (9,815 | ) | (10,834 | ) | (10,264 | ) | (6,254 | ) | (1,987 | ) | (10,264 | ) | (1,987 | ) | ||||||||||||||
Gain on sale of properties | (7,395 | ) | (7,851 | ) | (1 | ) | — | (62,729 | ) | — | (62,721 | ) | ||||||||||||||||
Other, net | — | 304 | 890 | 891 | 772 | 890 | 772 | |||||||||||||||||||||
Total costs and expenses | 25,712 | 20,817 | 45,395 | 14,823 | (32,966 | ) | 72,273 | (28,928 | ) | |||||||||||||||||||
Operating income (loss) | 24,223 | 4,043 | (6,654 | ) | 1,304 | 65,191 | 16,893 | 73,074 | ||||||||||||||||||||
Interest expense | (3,138 | ) | (2,937 | ) | (4,438 | ) | (1,828 | ) | (3,241 | ) | (4,105 | ) | (2,053 | ) | ||||||||||||||
Income (loss) before income taxes | $ | 21,085 | $ | 1,106 | $ | (11,092 | ) | $ | (524 | ) | $ | 61,950 | $ | 12,788 | $ | 71,021 | ||||||||||||
Income tax expense | — | — | (225 | ) | — | (122 | ) | (225 | ) | (122 | ) | |||||||||||||||||
Net income (loss) | $ | 21,085 | $ | 1,106 | $ | (11,317 | ) | $ | (524 | ) | $ | 61,828 | $ | 12,563 | $ | 70,899 | ||||||||||||
Cash Flow Data: | ||||||||||||||||||||||||||||
Net cash provided by operating activities | $ | 32,838 | $ | 12,672 | $ | 20,288 | $ | 15,463 | $ | 8,336 | ||||||||||||||||||
Net cash (used in) investing activities | (45,547 | ) | (24,947 | ) | (116,687 | ) | (100,273 | ) | (154,461 | ) | ||||||||||||||||||
Net cash provided by financing activities | 11,619 | 15,989 | 96,756 | 85,986 | 142,848 | |||||||||||||||||||||||
Other Financial Data: | ||||||||||||||||||||||||||||
Adjusted EBITDA | $ | 33,644 | $ | 24,953 | $ | 23,833 | $ | 11,049 | $ | 17,705 | $ | 60,202 | $ | 26,533 |
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Memorial | ||||||||||||||||||||
Production | ||||||||||||||||||||
Partners LP | ||||||||||||||||||||
Our Predecessor | Pro Forma | |||||||||||||||||||
Year Ended December 31, | As of June 30, | As of June 30, | ||||||||||||||||||
2008 | 2009 | 2010 | 2011 | 2011 | ||||||||||||||||
(Unaudited) | (Unaudited) | |||||||||||||||||||
(In thousands) | ||||||||||||||||||||
Balance Sheet Data: | ||||||||||||||||||||
Working capital | $ | (966 | ) | $ | 9,494 | $ | 4,116 | $ | 9,356 | $ | 4,364 | |||||||||
Total assets | 145,529 | 146,153 | 248,540 | 457,646 | 426,056 | |||||||||||||||
Total debt | 62,536 | 61,784 | 115,428 | 206,372 | 130,000 | |||||||||||||||
Partners’ capital | 54,576 | 72,988 | 105,801 | 220,435 | 280,694 |
• | Plus: |
• | Interest expense, including realized and unrealized losses on interest rate derivative contracts; | |
• | Income tax expense; | |
• | Depreciation, depletion and amortization; | |
• | Impairment of goodwill and long-lived assets (including oil and natural gas properties); | |
• | Accretion of asset retirement obligations; | |
• | Unrealized losses on commodity derivative contracts; | |
• | Losses on sale of assets and other, net; | |
• | Unit-based compensation expenses; | |
• | Exploration costs; | |
• | Acquisition related costs; and | |
• | Other non-routine items that we deem appropriate. |
• | Less: |
• | Interest income; | |
• | Income tax benefit; | |
• | Unrealized gains on commodity derivative contracts; | |
• | Gains on sale of assets and other, net; and | |
• | Other non-routine items that we deem appropriate. |
• | our operating performance as compared to that of other companies and partnerships in our industry, without regard to financing methods, capital structure or historical cost basis; and |
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• | the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness, and make distributions on our units. |
Memorial Production | ||||||||||||||||||||||||||||
Partners LP | ||||||||||||||||||||||||||||
Our Predecessor | Pro Forma | |||||||||||||||||||||||||||
Year | Six | |||||||||||||||||||||||||||
Ended | Months | |||||||||||||||||||||||||||
Six Months Ended | December | Ended | ||||||||||||||||||||||||||
Year Ended December 31, | June 30, | 31, | June 30, | |||||||||||||||||||||||||
2008 | 2009 | 2010 | 2010 | 2011 | 2010 | 2011 | ||||||||||||||||||||||
(Unaudited) | (Unaudited) | |||||||||||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||||||
Net income (loss) | $ | 21,085 | $ | 1,106 | $ | (11,317 | ) | $ | (524 | ) | $ | 61,828 | $ | 12,563 | $ | 70,899 | ||||||||||||
Interest expense | 3,138 | 2,937 | 4,438 | 1,828 | 3,241 | 4,105 | 2,053 | |||||||||||||||||||||
Income tax expense | — | — | 225 | — | 122 | 225 | 122 | |||||||||||||||||||||
Depreciation, depletion and amortization | 12,353 | 15,226 | 20,066 | 8,173 | 10,759 | 34,772 | 14,577 | |||||||||||||||||||||
Impairment | 14,166 | 3,480 | 11,800 | 3,319 | 2,893 | 9,509 | — | |||||||||||||||||||||
Accretion of asset retirement obligations | 224 | 320 | 663 | 251 | 466 | 1,072 | 534 | |||||||||||||||||||||
Unrealized (gains) losses on commodity derivative instruments | (10,301 | ) | 6,741 | (2,970 | ) | (2,888 | ) | 258 | (2,970 | ) | 258 | |||||||||||||||||
Acquisition related costs | — | 304 | 890 | 890 | 811 | 890 | 811 | |||||||||||||||||||||
Gain on sale of properties | (7,395 | ) | (7,851 | ) | (1 | ) | — | (62,729 | ) | — | (62,721 | ) | ||||||||||||||||
Unit-based compensation expense | — | — | — | — | — | — | — | |||||||||||||||||||||
Exploration costs | 374 | 2,690 | 39 | — | 56 | 36 | — | |||||||||||||||||||||
Adjusted EBITDA | $ | 33,644 | $ | 24,953 | $ | 23,833 | $ | 11,049 | $ | 17,705 | $ | 60,202 | $ | 26,533 | ||||||||||||||
Our Predecessor | ||||||||||||||||||||||||||||
Six Months Ended | ||||||||||||||||||||||||||||
Year Ended December 31, | June 30, | |||||||||||||||||||||||||||
2008 | 2009 | 2010 | 2010 | 2011 | ||||||||||||||||||||||||
(Unaudited) | ||||||||||||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||||||
Net cash provided by operating activities | $ | 32,838 | $ | 12,672 | $ | 20,288 | $ | 15,463 | $ | 8,336 | ||||||||||||||||||
Changes in working capital | (1,979 | ) | 8,840 | (742 | ) | (6,750 | ) | 4,136 | ||||||||||||||||||||
Interest expense | 3,138 | 2,937 | 4,438 | 1,828 | 3,241 | |||||||||||||||||||||||
Premiums paid for derivatives | — | — | — | — | 2,847 | |||||||||||||||||||||||
Premiums received for derivatives | — | — | — | — | (1,008 | ) | ||||||||||||||||||||||
Unrealized gain/(loss) on interest rate swaps | (327 | ) | 309 | (296 | ) | 27 | (445 | ) | ||||||||||||||||||||
Acquisition related costs | — | 304 | 890 | 890 | 811 | |||||||||||||||||||||||
Amortization of deferred financing fees | (26 | ) | (109 | ) | (745 | ) | (409 | ) | (213 | ) | ||||||||||||||||||
Adjusted EBITDA | $ | 33,644 | $ | 24,953 | $ | 23,833 | $ | 11,049 | $ | 17,705 | ||||||||||||||||||
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Partnership | ||||
Properties as of | ||||
December 31, | ||||
2010 | ||||
Estimated Pro Forma Proved Reserves | ||||
Oil (MBbls) | 2,002 | |||
NGLs (MBbls) | 4,502 | |||
Natural gas (MMcf) | 285,676 | |||
Total (MMcfe)(1) | 324,697 | |||
Proved developed (MMcfe) | 264,572 | |||
Proved undeveloped (MMcfe) | 60,125 | |||
Proved developed reserves as a percentage of total proved reserves | 81 | % | ||
Standardized measure (in millions)(2)(3) | $ | 359.2 | ||
Oil and Natural Gas Prices(4) | ||||
Oil — WTI Posting (Plains) per Bbl | $ | 75.96 | ||
Natural gas — NYMEX–Henry Hub per MMBtu | $ | 4.38 |
(1) | Determined using a ratio of six Mcf of natural gas to one Bbl of oil, condensate or NGLs based on an approximate energy equivalency. This is an energy content correlation and does not reflect a value or price relationship between the commodities. | |
(2) | Standardized measure is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC without giving effect to non-property related expenses, such as general and administrative expenses, interest and income tax expenses, or to depreciation, depletion and amortization. The future cash flows are discounted using an annual discount rate of 10%. Because we are a limited partnership, we are generally not subject to federal income taxes and thus make no provision for federal income taxes in the calculation of our standardized measure. Standardized measure does not give effect to derivative transactions. We expect to hedge a substantial portion of our future estimated production from total proved producing reserves. For a description of our expected commodity derivative contracts, please read “Management’s Discussion and |
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Analysis of Financial Condition and Results of Operations — Pro Forma Liquidity and Capital Resources — Commodity Derivative Contracts.” | ||
(3) | Because we are subject to Texas margin tax, our standardized measure was negatively impacted by $5.0 million. | |
(4) | Our estimated net proved reserves and related standardized measure were determined using index prices for oil and natural gas, without giving effect to derivative contracts, held constant throughout the life of the properties. These prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. |
Memorial Production | ||||||||
Partners LP | ||||||||
Pro Forma | ||||||||
Six Months | ||||||||
Year Ended | Ended | |||||||
December 31, | June 30, | |||||||
2010 | 2011 | |||||||
(Unaudited) | ||||||||
Production and operating data: | ||||||||
Net production volumes: | ||||||||
Oil (MBbls) | 107 | 50 | ||||||
NGLs (MBbls) | 272 | 114 | ||||||
Natural gas (MMcf) | 16,713 | 7,903 | ||||||
Total (MMcfe) | 18,985 | 8,888 | ||||||
Average net production (MMcfe/d) | 52 | 49 | ||||||
Average sales price:(1) | ||||||||
Oil (per Bbl) | $ | 74.35 | $ | 94.90 | ||||
NGLs (per Bbl) | $ | 37.41 | $ | 48.05 | ||||
Natural gas (per Mcf) | $ | 4.17 | $ | 4.26 | ||||
Average price per Mcfe | $ | 4.62 | $ | 4.94 | ||||
Average unit costs per Mcfe: | ||||||||
Lease operating expenses | $ | 1.21 | $ | 1.45 | ||||
Production taxes | $ | 0.39 | $ | 0.40 | ||||
General and administrative expenses | $ | 0.31 | $ | 0.39 | ||||
Depreciation, depletion and amortization | $ | 1.83 | $ | 1.64 |
(1) | Prices do not include the effects of derivative cash settlements. |
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• | the amount of oil, natural gas and NGLs we produce; | |
• | the prices at which we sell our oil, natural gas and NGL production; |
• | the amount and timing of settlements of our commodity derivatives; |
• | the level of our operating costs, including maintenance capital expenditures and payments to our general partner; and | |
• | the level of our interest expense, which depends on the amount of our indebtedness and the interest payable thereon. |
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• | high costs, shortages or delivery delays of rigs, equipment, labor or other services; | |
• | composition of sour natural gas, including sulfur and mercaptan content; | |
• | unexpected operational events and conditions; | |
• | adverse weather conditions and natural disasters; | |
• | facility or equipment malfunctions and equipment failures or accidents, including acceleration of deterioration of our facilities and equipment due to the highly corrosive nature of sour natural gas; | |
• | loss of drilling fluid circulation; | |
• | fires, blowouts, surface craterings and explosions; and | |
• | uncontrollable flows of oil, natural gas or well fluids. |
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• | unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with their owners; | |
• | unable to obtain financing for such acquisitions on economically acceptable terms; or | |
• | outbid by competitors. |
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• | the validity of our assumptions about estimated proved reserves, future production, revenues, capital expenditures, operating expenses and costs; | |
• | an inability to successfully integrate the assets or businesses we acquire; | |
• | a decrease in our liquidity by using a significant portion of our available cash or borrowing capacity to finance acquisitions; | |
• | a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions; | |
• | the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which any indemnity we receive is inadequate; | |
• | the diversion of management’s attention from other business concerns; | |
• | mistaken assumptions about the overall cost of equity or debt; | |
• | an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets; and | |
• | the occurrence of other significant changes, such as impairment of oil and natural gas properties, goodwill or other intangible assets, asset devaluation or restructuring charges. |
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• | the nature and timing of drilling and operational activities; | |
• | the timing and amount of capital expenditures; | |
• | Memorial Resource’s or the operators’ expertise and financial resources; | |
• | the approval of other participants in such properties; and | |
• | the selection and application of suitable technology. |
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• | neither our partnership agreement nor any other agreement requires Memorial Resource, the Funds or NGP to pursue a business strategy that favors us. The directors and officers of Memorial Resource, the Funds and their respective affiliates (including NGP) have a fiduciary duty to make decisions in the best interests of their respective equity holders, which may be contrary to our interests; | |
• | our general partner is allowed to take into account the interests of parties other than us, such as its owner, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders; | |
• | Memorial Resource, the Funds and their affiliates (including NGP) are not limited in their ability to compete with us, including with respect to future acquisition opportunities, and are under no obligation to offer assets to us. Please read “Conflicts of Interest and Fiduciary Duties — Conflicts of Interest — Memorial Resource, the Funds and other affiliates of our general partner will not be limited in their ability to compete with us, which could cause conflicts of interest and limit our ability to acquire additional assets or businesses”; | |
• | except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval; | |
• | many of the officers and directors of our general partner who will provide services to us will devote time to affiliates of our general partner, including Memorial Resource, the Funds,and/or NGP, and may be compensated for services rendered to such affiliates; | |
• | our general partner has limited its liability and reduced its fiduciary duties, and has also restricted the remedies available to our unitholders for actions that, without such limitations, reductions, and restrictions, might constitute breaches of fiduciary duty. By purchasing common units, unitholders are consenting to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable law; | |
• | our general partner determines the amount and timing of our drilling program and related capital expenditures, asset purchases and sales, borrowings, issuance of additional partnership interests, other investments, including investment capital expenditures in other partnerships with which our general partner is or may become affiliated, and the creation, reduction or increase of cash reserves, each of which can affect the amount of cash that is distributed to unitholders; | |
• | our general partner determines whether a cash expenditure is classified as a growth capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and to our general partner, the amount of adjusted operating surplus in any given period and the ability of the subordinated units to convert into common units; | |
• | we and our general partner will enter into an omnibus agreement with Memorial Resource in connection with this offering, pursuant to which, among other things, Memorial Resource will operate our assets and perform other management, administrative, and operating services for us and our general partner; | |
• | our general partner is entitled to determine which costs, including allocated overhead, incurred by it and its affiliates, including Memorial Resource, are reimbursable by us, which will include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf, and expenses allocated to our general partner by its affiliates; | |
• | our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period; | |
• | our partnership agreement permits us to classify up to $ million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions on our subordinated units or to our general partner in respect of the general partner interest or the incentive distribution rights; |
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• | our general partner decides whether to retain separate counsel, accountants, or others to perform services for us; | |
• | our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the conflicts committee of the board of directors of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations; | |
• | our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf; | |
• | our general partner intends to limit its liability regarding our contractual and other obligations and, in some circumstances, is entitled to be indemnified by us; | |
• | our general partner may exercise its limited right to call and purchase common units if it and its affiliates own more than 80% of the common units; | |
• | our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates, including Memorial Resource, the Funds and NGP; and | |
• | our general partner decides whether to retain separate counsel, accountants or others to perform services for us. |
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• | an omnibus agreement pursuant to which, among other things, Memorial Resource will provide management, administrative and operating services for us and our general partner; and |
• | a tax sharing agreement pursuant to which we will pay Memorial Resource (or its applicable affiliate(s)) our share of state and local income and other taxes for which our results are included in a combined or consolidated tax return filed by Memorial Resource or its applicable affiliate(s). It is possible that Memorial Resource or its applicable affiliate(s) may use its tax attributes to cause its combined or consolidated group, of which we may be a member for this purpose, to owe less or no tax. In such a situation, we would pay Memorial Resource or its applicable affiliate(s) the tax we would have owed had the tax attributes not been available or used for our benefit, even though Memorial Resource or its applicable affiliate(s) had no cash tax expense for that period. Currently, the Texas margin tax (which has a maximum effective tax rate of 0.7% of federal gross income apportioned to Texas) is the only tax that will be included in a combined or consolidated tax return with Memorial Resource or its applicable affiliate(s). |
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• | permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its limited call right, the exercise of its rights to transfer or vote the units it owns, the exercise of its registration rights and its determination whether or not to consent to any merger or consolidation involving us or to any amendment to the partnership agreement; | |
• | provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as general partner so long as such decisions are made in good faith and with the honest belief that the decision was in our best interest; | |
• | generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner acting in good faith and not |
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involving a vote of unitholders must be (i) on terms no less favorable to us than those generally being provided to or available from unrelated third parties or (ii) must be “fair and reasonable” to us, as determined by our general partner in good faith. In determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us; |
• | provides that our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and | |
• | provides that in resolving conflicts of interest, it will be presumed that in making its decision our general partner’s board of directors or the conflicts committee of our general partner’s board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. |
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• | our unitholders’ proportionate ownership interest in us will decrease; | |
• | the amount of cash available for distribution on each unit may decrease; | |
• | because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase; | |
• | the ratio of taxable income to distributions may increase; | |
• | the relative voting strength of each previously outstanding unit may be diminished; and | |
• | the market price of our common units may decline. |
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• | a court or government agency determined that we were conducting business in a state but had not complied with that particular state’s partnership statute; or | |
• | a unitholder’s right to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business. |
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• | changes in commodity prices; | |
• | changes in securities analysts’ recommendations and their estimates of our financial performance; | |
• | public reaction to our press releases, announcements and filings with the SEC; | |
• | fluctuations in broader securities market prices and volumes, particularly among securities of oil and natural gas companies and securities of publicly traded limited partnerships and limited liability companies; | |
• | changes in market valuations of similar companies; | |
• | departures of key personnel; | |
• | commencement of or involvement in litigation; | |
• | variations in our quarterly results of operations or those of other oil and natural gas companies; | |
• | variations in the amount of our quarterly cash distributions to our unitholders; | |
• | future issuances and sales of our common units; and | |
• | changes in general conditions in the U.S. economy, financial markets or the oil and natural gas industry. |
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• | general economic and market conditions, including interest rates, prevailing at the time we desire to issue securities or borrow funds; | |
• | conditions in the oil and natural gas industry; | |
• | the market price of, and demand for, our common units; | |
• | our results of operations and financial condition; and | |
• | prices for oil, NGLs and natural gas. |
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Sources of Cash (In millions) | Uses of Cash (In millions) | |||||||||
Gross proceeds from this offering(1) | $ | Cash consideration to Memorial Resource | $ | |||||||
Borrowings under new revolving credit facility(1) | 130.0 | Underwriting discounts, structuring fees, fees and expenses associated with our new revolving credit facility and other offering and formation-related fees and expenses payable by us | ||||||||
Total | $ | Total | $ | |||||||
(1) | If the underwriters exercise their option to purchase additional common units in full, the gross proceeds would be $ and the amount borrowed under our new revolving credit facility would be approximately $ million. |
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• | the historical capitalization of our predecessor as of June 30, 2011; and | |
• | our pro forma capitalization as of June 30, 2011, adjusted to reflect the issuance and sale of common units to the public at an assumed initial offering price of $ per common unit (the midpoint of the price range set forth on the cover of this prospectus), the other formation transactions described under “Summary — Our Partnership Structure and Formation Transactions,” and the application of the net proceeds from this offering as described under “Use of Proceeds.” |
As of June 30, 2011 | ||||||||
Pro Forma | ||||||||
Our | Memorial | |||||||
Predecessor | Production | |||||||
Historical | Partners LP | |||||||
(In thousands) | ||||||||
Long-term debt(1) | $ | 206,287 | $ | |||||
Partners’ capital/net equity: | ||||||||
Predecessor partners’ capital | 220,435 | |||||||
Common units held by purchasers in this offering | — | |||||||
Common units held by Memorial Resource | — | |||||||
Subordinated units held by Memorial Resource | — | |||||||
General partner interest | — | |||||||
Total partners’ capital/net equity(2) | 220,435 | |||||||
Total capitalization | $ | 426,722 | $ | |||||
(1) | We intend to enter into a $ million revolving credit facility, approximately $ million of which will be available for borrowing upon the completion of the transactions described under “Summary — Our Partnership Structure and Formation Transactions.” After giving effect to the transactions described under “Summary — Our Partnership Structure and Formation Transactions,” including our expected borrowing of $130.0 million under our new revolving credit facility, we will have approximately $ million of borrowing capacity. We do not anticipate having any outstanding letters of credit against our borrowing capacity at the closing of this offering. For additional information on our new revolving credit facility, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Pro Forma Liquidity and Capital Resources — New Revolving Credit Facility.” |
(2) | A $1.00 increase or decrease in the assumed initial public offering price per common unit would increase or decrease, respectively, the net proceeds (and the cash portion of the consideration to be paid to Memorial Resource for the Partnership Properties) by approximately $ million and would change our total partners’ capital by approximately $ million, assuming the number of common units offered by us, as set forth on the cover page of this prospectus, remains the same. |
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Assumed initial offering price per common unit | $ | |||||||
Pro forma as adjusted net tangible book value per unit before this offering(1) | $ | |||||||
Increase in net tangible book value per unit attributable to purchasers in this offering | ||||||||
Less: Pro forma as adjusted net tangible book value per unit after this offering(2) | ||||||||
Immediate dilution in net tangible book value per unit to purchasers in this offering(3) | $ | |||||||
(1) | Determined by dividing the pro forma net tangible book value of our net assets immediately prior to the offering by the number of units ( common units and subordinated units) to be issued to Memorial Resource as partial consideration for their contribution of the Partnership Properties to us and the general partner units to be issued to our general partner. | |
(2) | Determined by dividing our pro forma as adjusted net tangible book value, after giving effect to the application of the expected net proceeds of this offering, by the total number of units to be outstanding after this offering ( common units, subordinated units, and general partner units). | |
(3) | If the assumed initial offering price were to increase or decrease by $1.00 per common unit, then dilution in pro forma as adjusted net tangible book value per unit would equal $ or $ , respectively. The information discussed above is illustrative only and will be adjusted based on the actual public offering price and other terms of this offering determined at pricing. |
Units Acquired | Total Consideration | |||||||||||||||
Number | Percent | $ | Percent | |||||||||||||
(In millions) | ||||||||||||||||
General partner and its affiliates(1)(2) | % | $ | % | |||||||||||||
Purchasers in the offering(3) | % | % | ||||||||||||||
Total | 100.0 | % | $ | 100.0 | % | |||||||||||
(1) | Upon the consummation of the transactions contemplated by this prospectus, and assuming the underwriters do not exercise their option to purchase additional common units, our general partner and its affiliates will own common units, subordinated units, and general partner units. | |
(2) | The assets contributed by Memorial Resource were recorded at historical cost in accordance with GAAP. Total consideration provided by affiliates of our general partner is equal to the pro forma net tangible book value of such assets as of June 30, 2011. | |
(3) | Total consideration is after deducting underwriting discounts and estimated offering expenses. |
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• | Our cash distribution policy may be subject to restrictions on distributions under our new revolving credit facility or other debt agreements that we may enter into in the future. Specifically, we anticipate that the agreement related to our new revolving credit facility will contain financial tests and covenants that we must satisfy. These financial ratios and covenants are described under the caption “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Pro Forma Liquidity and Capital Resources — New Revolving Credit Facility.” Should we be unable to satisfy these restrictions, or if a default occurs under our new revolving credit facility, we would be prohibited from making cash distributions to our unitholders notwithstanding our stated cash distribution policy. | |
• | Our general partner will have the authority to establish reserves for the prudent conduct of our business and for future cash distributions to our unitholders, and the establishment of or increase in those reserves could result in a reduction in cash distributions to our unitholders from levels we currently anticipate under our stated distribution policy. Any determination to establish or increase reserves made by our general partner in good faith will be binding on the unitholders. We intend to reserve a portion of our cash generated from operations to fund our maintenance capital expenditures. Over a longer |
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period of time, if our general partner does not set aside sufficient cash reserves or make sufficient cash expenditures to maintain our asset base, we will be unable to pay the minimum quarterly distribution from cash generated from operations and would therefore expect to reduce our distributions. We are unlikely to be able to sustain our current level of distributions without making capital expenditures that maintain the current production levels of our oil and natural gas properties. Decreases in commodity prices from current levels will adversely affect our ability to pay distributions. If our asset base decreases and we do not reduce our distributions, a portion of the distributions may be considered a return of part of our unitholders’ investment in us as opposed to a return on our unitholders’ investment. |
• | Prior to making any distribution on our common units, we will reimburse our general partner and its affiliates for all direct and indirect expenses they incur on our behalf. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us, and Memorial Resource will be entitled for such reimbursement under the omnibus agreement. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates will reduce the amount of cash available to pay cash distributions to our unitholders. | |
• | Although our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including the provisions requiring us to make cash distributions contained therein, may be amended. Our partnership agreement may not be amended during the subordination period without the approval of our public common unitholders, other than in certain limited circumstances where no unitholder approval is required. However, our partnership agreement can be amended with the consent of our general partner and the approval of the holders of a majority of our outstanding common units (including common units that are held by Memorial Resource and its affiliates) after the subordination period has ended. Upon consummation of this offering, Memorial Resource will own our general partner and will control the voting of an aggregate of approximately % of our outstanding common units and all of our subordinated units. Assuming we do not issue any additional common units and Memorial Resource does not transfer its common units, Memorial Resource will have the ability to amend our partnership agreement without the approval of any other unitholder once the subordination period ends. | |
• | Even if our cash distribution policy is not modified or revoked, the amount of distributions we pay under our cash distribution policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement, our new revolving credit facility and any other agreements we may enter into in the future. | |
• | UnderSection 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. | |
• | We may lack sufficient cash to pay distributions to our unitholders due to a number of factors, including reductions in commodity prices, reductions in our oil and natural gas production, increases in our general and administrative expenses, principal and interest payments on our outstanding debt, tax expenses, working capital requirements and anticipated cash needs. For a discussion of additional factors that may affect our ability to pay distributions, please read “Risk Factors.” | |
• | If and to the extent our cash available for distribution materially declines, we may reduce our quarterly distribution in order to service or repay our debt or fund growth capital expenditures. | |
• | All available cash distributed by us on any date from any source will be treated as distributed from operating surplus until the sum of all available cash distributed since the closing of this offering equals the cumulative operating surplus from the closing of this offering through the end of the quarter immediately preceding that distribution. We anticipate that distributions from operating surplus will |
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generally not represent a return of capital. However, operating surplus, as defined in our partnership agreement, includes certain components that represent non-operating sources of cash, including a cash basket equal to $ million and working capital borrowings. Consequently, it is possible that distributions from operating surplus may represent a return of capital. For example, the $ million cash basket would allow us to distribute as operating surplus cash proceeds we receive in the future from non-operating sources such as asset sales, issuances of securities and long-term borrowings, which would represent a return of capital. Distributions representing a return of capital could result in a corresponding decrease in our asset base. Additionally, any cash distributed by us in excess of operating surplus will be deemed to be capital surplus under our partnership agreement. Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this initial public offering, which is similar to a return of capital. Distributions from capital surplus could result in a corresponding decrease in our asset base. We do not anticipate that we will make any distributions from capital surplus. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions — Operating Surplus and Capital Surplus” and “Provisions of Our Partnership Agreement Relating to Cash Distributions — Distributions from Capital Surplus — Effect of a Distribution from Capital Surplus.” |
• | Our ability to make distributions to our unitholders depends on the performance of our operating subsidiaries and its ability to distribute cash to us. The ability of our operating subsidiaries to make distributions to us may be restricted by, among other things, the provisions of existing and future indebtedness, applicable state partnership and limited liability company laws and other laws and regulations. |
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No Exercise of the Underwriters’ | Full Exercise of the Underwriters’ | |||||||||||||||||||||||
Option to Purchase Additional Common Units | Option to Purchase Additional Common Units | |||||||||||||||||||||||
Distributions | Distributions | |||||||||||||||||||||||
Number of | One | Four | Number of | One | Four | |||||||||||||||||||
Units | Quarter | Quarters | Units | Quarter | Quarters | |||||||||||||||||||
Common units held by purchasers in this offering(1) | $ | $ | $ | $ | ||||||||||||||||||||
Common units held by Memorial Resource and its affiliates(1) | ||||||||||||||||||||||||
Subordinated units | ||||||||||||||||||||||||
General partner units | ||||||||||||||||||||||||
Total | $ | $ | $ | $ | ||||||||||||||||||||
(1) | Does not include any common units that may be issued under the long-term incentive plan that our general partner is expected to adopt prior to the closing of this offering. |
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• | “Unaudited Pro Forma Available Cash for the Year Ended December 31, 2010 and Twelve Months Ended June 30, 2011,” in which we present the amount of cash we would have had available for distribution to our unitholders and our general partner for the year ended December 31, 2010 and the twelve months ended June 30, 2011, based on our unaudited pro forma financial statements. Our calculation of unaudited pro forma available cash in this table should only be viewed as a general indication of the amount of available cash that we might have generated had the transactions contemplated in this prospectus occurred in an earlier period. | |
• | “Estimated Cash Available for Distribution,” in which we demonstrate our ability to generate the minimum Adjusted EBITDA necessary for us to have sufficient cash available for distribution to pay the full minimum quarterly distribution on all the outstanding units, including our general partner units, for the twelve months ending September 30, 2012. |
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Unaudited Pro Forma Cash Available for Distribution
Pro Forma | ||||||||
Year Ended | Twelve Months Ended | |||||||
December 31, 2010 | June 30, 2011 | |||||||
(In thousands, except per unit data) | ||||||||
Net income (loss) | $ | 12,563 | $ | 70,658 | ||||
Interest expense | 4,105 | 4,105 | ||||||
Income tax expense | 225 | 347 | ||||||
Depreciation, depletion and amortization | 34,772 | 31,363 | ||||||
Impairment | 9,509 | 6,190 | ||||||
Accretion of asset retirement obligations | 1,072 | 1,080 | ||||||
Unrealized (gains) losses on derivative instruments | (2,970 | ) | 168 | |||||
Acquisition related costs | 890 | 811 | ||||||
(Gain) loss on sale of properties | — | (62,721 | ) | |||||
Unit-based compensation expense | — | — | ||||||
Exploration costs | 36 | 36 | ||||||
Adjusted EBITDA(1) | $ | 60,202 | $ | 52,037 | ||||
Less: | ||||||||
Cash interest expense(2) | $ | 3,705 | $ | 3,705 | ||||
Estimated average maintenance capital expenditures(3) | 9,200 | 9,200 | ||||||
Pro forma available cash(4) | $ | 47,297 | $ | 39,132 | ||||
Pro forma annualized distributions per unit(5) | $ | $ | ||||||
Pro forma estimated annual cash distributions: | ||||||||
Distributions on common units held by purchasers in this offering(5) | $ | $ | ||||||
Distributions on common units held by Memorial Resource and its affiliates(5) | ||||||||
Distributions on subordinated units(5) | ||||||||
Distributions on general partner units(5) | ||||||||
Total estimated annual cash distributions(5) | $ | $ | ||||||
Excess (Shortfall)(5) | $ | $ | ||||||
Percent of minimum quarterly distributions payable to common unitholders | ||||||||
Percent of minimum quarterly distributions payable to subordinated unitholders |
(1) | Adjusted EBITDA is defined in “Summary — Non-GAAP Financial Measure.” |
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(2) | In connection with this offering, we intend to enter into a new $ million revolving credit facility under which we expect to incur approximately $130.0 million of borrowings upon the closing of this offering. The pro forma cash interest expense is based on $130.0 million of borrowings at an assumed weighted-average rate of 2.85%. If the interest rate used to calculate this interest were 1% higher or lower, our annual cash interest expense would increase or decrease, respectively, by $1.3 million. |
(3) | Historically, our predecessor did not make a distinction between maintenance and growth capital expenditures. For purposes of the presentation of Unaudited Pro Forma Cash Available for Distribution, we have estimated that approximately $9.2 million of our predecessor’s capital expenditures were maintenance capital expenditures for the Partnership Properties for the respective period. Our estimates accounted for our targeted average net production from our assets of 49 MMcfe/d through December 31, 2015, our decline rate for our existing proved developed producing reserves of approximately 9% and the amount of capital expenditures required annually to be expended on reserve development to maintain the reserve base and replace the production lost to depletion. To the extent capital expenditures exceed our targeted annual maintenance capital expenditure of $9.2 million, such expenditures would be considered growth capital expenditures and we would expect an increase in production and cash flows accordingly. | |
(4) | Does not reflect impact of $2.5 million of estimated incremental annual general and administrative expenses that we expect to incur associated with being a publicly traded partnership. Please read “— Assumptions and Considerations — Capital Expenditures and Expenses.” | |
(5) | The following table provides pro forma estimated annual cash distributions and the excess (shortfall) if the underwriters’ option to purchase additional common units is exercised in full. |
Pro Forma | ||||||||
Year Ended | Twelve Months Ended | |||||||
December 31, 2010 | June 30, 2011 | |||||||
(In thousands, except per unit data) | ||||||||
Pro forma annualized distributions per unit | $ | $ | ||||||
Pro forma estimated annual cash distributions: | ||||||||
Distributions on common units held by purchasers in this offering | $ | $ | ||||||
Distributions on common units held by Memorial Resource and its affiliates | ||||||||
Distributions on subordinated units | ||||||||
Distributions on general partner units | ||||||||
Total estimated annual cash distributions | $ | $ | ||||||
Excess (Shortfall) | $ | $ | ||||||
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• | Plus: |
• | Interest expense, including realized and unrealized losses on interest rate derivative contracts; | |
• | Income tax expense; | |
• | Depreciation, depletion and amortization; | |
• | Impairment of goodwill and long-lived assets (including oil and natural gas properties); | |
• | Accretion of asset retirement obligations; | |
• | Unrealized losses on commodity derivative contracts; | |
• | Losses on sale of assets and other, net; | |
• | Unit-based compensation expenses; | |
• | Exploration costs; | |
• | Acquisition related costs; and | |
• | Other non-routine items that we deem appropriate. |
• | Less: |
• | Interest income; | |
• | Income tax benefit; | |
• | Unrealized gains on commodity derivative contracts; | |
• | Gains on sale of assets and other, net; and | |
• | Other non-routine items that we deem appropriate. |
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Estimated Adjusted EBITDA
Assuming No Exercise of the Underwriters’ Option to Purchase Additional Common Units
Forecasted | ||||||||||||||||||||
Three Months Ending | Twelve Months Ending | |||||||||||||||||||
December 31, 2011 | March 31, 2012 | June 30, 2012 | September 30, 2012 | September 30, 2012 | ||||||||||||||||
(In millions, except for per unit amounts) | ||||||||||||||||||||
Operating revenue and realized commodity derivative gains (losses)(1) | $ | 23.3 | $ | 23.8 | $ | 24.1 | $ | 24.4 | $ | 95.6 | ||||||||||
Less: | ||||||||||||||||||||
Lease operating expenses | 4.6 | 4.6 | 4.6 | 4.6 | 18.3 | |||||||||||||||
Production and ad valorem taxes | 2.0 | 2.1 | 2.1 | 2.1 | 8.3 | |||||||||||||||
General and administrative expenses | 1.3 | 1.3 | 1.3 | 1.3 | 5.0 | |||||||||||||||
Depreciation, depletion and amortization | 9.1 | 9.1 | 9.2 | 9.3 | 36.8 | |||||||||||||||
Interest expense | 0.9 | 0.9 | 0.9 | 0.9 | 3.5 | |||||||||||||||
Net income excluding unrealized derivative gains (losses) | $ | 5.5 | $ | 5.9 | $ | 6.0 | $ | 6.3 | $ | 23.7 | ||||||||||
Adjustments to reconcile net income excluding unrealized derivative gains (losses) to estimated Adjusted EBITDA: | ||||||||||||||||||||
Add: | ||||||||||||||||||||
Depreciation, depletion and amortization | $ | 9.1 | $ | 9.1 | $ | 9.2 | $ | 9.3 | $ | 36.8 | ||||||||||
Interest expense | 0.9 | 0.9 | 0.9 | 0.9 | 3.5 | |||||||||||||||
Estimated Adjusted EBITDA | $ | 15.5 | $ | 15.9 | $ | 16.1 | $ | 16.5 | $ | 64.0 | ||||||||||
Adjustments to reconcile estimated Adjusted EBITDA to cash available for distribution: | ||||||||||||||||||||
Less: | ||||||||||||||||||||
Cash interest expense(2) | $ | 0.9 | $ | 0.9 | $ | 0.9 | $ | 0.9 | $ | 3.5 | ||||||||||
Estimated average maintenance capital expenditures(3) | 1.5 | 4.2 | 1.1 | 2.4 | 9.2 | |||||||||||||||
Estimated cash available for distribution | $ | 13.1 | $ | 10.9 | $ | 14.2 | $ | 13.2 | $ | 51.3 | ||||||||||
Annualized minimum quarterly distribution per unit | $ | |||||||||||||||||||
Estimated annual cash distributions: | ||||||||||||||||||||
Distributions on common units held by purchasers in this offering | $ | |||||||||||||||||||
Distributions on common units held by Memorial Resource and its affiliates | ||||||||||||||||||||
Distributions on subordinated units | ||||||||||||||||||||
Distributions on general partner units | ||||||||||||||||||||
Total estimated annual cash distributions | $ | |||||||||||||||||||
Excess cash available for distribution | $ | |||||||||||||||||||
Minimum estimated Adjusted EBITDA: | ||||||||||||||||||||
Estimated Adjusted EBITDA | $ | 15.5 | $ | 15.9 | $ | 16.1 | $ | 16.5 | $ | 64.0 | ||||||||||
Less: | ||||||||||||||||||||
Excess cash available for distributions(4) | ||||||||||||||||||||
Minimum estimated Adjusted EBITDA | $ | |||||||||||||||||||
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Estimated Adjusted EBITDA
Assuming Full Exercise of the Underwriters’ Option to Purchase Additional Common Units
Forecasted | ||||||||||||||||||||
Three Months Ending | Twelve Months Ending | |||||||||||||||||||
December 31, 2011 | March 31, 2012 | June 30, 2012 | September 30, 2012 | September 30, 2012 | ||||||||||||||||
(In millions, except for per unit amounts) | ||||||||||||||||||||
Operating revenue and realized commodity derivative gains (losses)(1) | $ | 23.3 | $ | 23.8 | $ | 24.1 | $ | 24.4 | $ | 95.6 | ||||||||||
Less: | ||||||||||||||||||||
Lease operating expenses | 4.6 | 4.6 | 4.6 | 4.6 | 18.3 | |||||||||||||||
Production and ad valorem taxes | 2.0 | 2.1 | 2.1 | 2.1 | 8.3 | |||||||||||||||
General and administrative expenses | 1.3 | 1.3 | 1.3 | 1.3 | 5.0 | |||||||||||||||
Depreciation, depletion and amortization | 9.1 | 9.1 | 9.2 | 9.3 | 36.8 | |||||||||||||||
Interest expense | 0.7 | 0.7 | 0.7 | 0.7 | 2.7 | |||||||||||||||
Net income excluding unrealized derivative gains (losses) | $ | 5.7 | $ | 6.1 | $ | 6.2 | $ | 6.5 | $ | 24.5 | ||||||||||
Adjustments to reconcile net income excluding unrealized derivative gains (losses) to estimated Adjusted EBITDA: | ||||||||||||||||||||
Add: | ||||||||||||||||||||
Depreciation, depletion and amortization | $ | 9.1 | $ | 9.1 | $ | 9.2 | $ | 9.3 | $ | 36.8 | ||||||||||
Interest expense | 0.7 | 0.7 | 0.7 | 0.7 | 2.7 | |||||||||||||||
Estimated Adjusted EBITDA | $ | 15.5 | $ | 15.9 | $ | 16.1 | $ | 16.5 | $ | 64.0 | ||||||||||
Adjustments to reconcile estimated Adjusted EBITDA to cash available for distribution: | ||||||||||||||||||||
Less: | ||||||||||||||||||||
Cash interest expense(2) | $ | 0.7 | $ | 0.7 | $ | 0.7 | $ | 0.7 | $ | 2.7 | ||||||||||
Estimated average maintenance capital expenditures(3) | 1.5 | 4.2 | 1.1 | 2.4 | 9.2 | |||||||||||||||
Estimated cash available for distribution | $ | 13.3 | $ | 11.0 | $ | 14.3 | $ | 13.4 | $ | 52.1 | ||||||||||
Annualized minimum quarterly distribution per unit | $ | |||||||||||||||||||
Estimated annual cash distributions: | ||||||||||||||||||||
Distributions on common units held by purchasers in this offering | $ | |||||||||||||||||||
Distributions on common units held by Memorial Resource and its affiliates | ||||||||||||||||||||
Distributions on subordinated units | ||||||||||||||||||||
Distributions on general partner units | ||||||||||||||||||||
Total estimated annual cash distributions | $ | |||||||||||||||||||
Excess cash available for distribution | $ | |||||||||||||||||||
Minimum estimated Adjusted EBITDA: | ||||||||||||||||||||
Estimated Adjusted EBITDA | $ | 15.5 | $ | 15.9 | $ | 16.1 | $ | 16.5 | $ | 64.0 | ||||||||||
Less: | ||||||||||||||||||||
Excess cash available for distributions(4) | ||||||||||||||||||||
Minimum estimated Adjusted EBITDA | $ | |||||||||||||||||||
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(1) | Includes the forecasted effect of cash settlements of commodity derivative instruments. |
(2) | In connection with this offering, we intend to enter into a new $ million revolving credit facility under which we expect to incur approximately $130.0 million of borrowings upon the closing of this offering. The pro forma cash interest expense is based on $130.0 million of borrowings at an assumed weighted-average rate of 2.99%. If the interest rate used to calculate this interest were 1% higher or lower, our annual cash interest expense would increase or decrease, respectively, by $1.2 million. |
(3) | In calculating the estimated cash available for distribution, we have included our estimated maintenance capital expenditures for the twelve months ending September 30, 2012. To maintain our targeted average net production from our assets of 49MMcfe/d through December 31, 2015, we expect to annually incur approximately $9.2 million of capital expenditures for the twelve months ending September 30, 2012 based on our reserve reports as of December 31, 2010. | |
(4) | We intend to retain any excess cash to repay indebtedness or for other general partnership purposes. |
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Forecasted | ||||||||||||
Pro Forma Year | Pro Forma | Twelve Months | ||||||||||
Ended | Twelve Months | Ending | ||||||||||
December 31, | Ended | September 30, | ||||||||||
2010 | June 30, 2011 | 2012 | ||||||||||
(Unaudited) | ||||||||||||
Annual Production: | ||||||||||||
Oil (MBbl) | 107 | 100 | 100 | |||||||||
NGLs (MBbl) | 272 | 239 | 186 | |||||||||
Natural Gas (MMcf) | 16,713 | 16,225 | 16,262 | |||||||||
Total (MMcfe) | 18,985 | 18,258 | 17,976 | |||||||||
Average Net Production: | ||||||||||||
Oil (MBbl/d) | 0.3 | 0.3 | 0.3 | |||||||||
NGLs (MBbl/d) | 0.8 | 0.7 | 0.5 | |||||||||
Natural Gas(MMcf/d) | 45.8 | 44.5 | 44.4 | |||||||||
Total (MMcfe/d) | 52.0 | 50.0 | 49.1 |
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Forecasted | ||||||||||||
Pro Forma | Pro Forma | Twelve Months | ||||||||||
Year Ended | Twelve Months | Ending | ||||||||||
December 31, | Ended | September 30, | ||||||||||
2010 | June 30, 2011 | 2012 | ||||||||||
(Unaudited) | ||||||||||||
Average oil sales prices: | ||||||||||||
NYMEX-WTI oil price per Bbl | $ | 79.59 | $ | 90.79 | $ | 98.45 | ||||||
Differential to NYMEX-WTI oil per Bbl | $ | (5.24 | ) | $ | (5.98 | ) | $ | (4.27 | ) | |||
Realized oil sales price per Bbl (excluding cash settlements of derivatives) | $ | 74.35 | $ | 84.81 | $ | 94.18 | ||||||
Realized oil sales price per Bbl (including cash settlements of derivatives)(1)(2) | $ | 74.35 | $ | 84.81 | $ | 93.67 | ||||||
Average natural gas liquids sales prices: | ||||||||||||
NYMEX-WTI oil price per Bbl | $ | 79.59 | $ | 90.79 | $ | 98.45 | ||||||
Differential to NYMEX-WTI oil price per Bbl | $ | (42.18 | ) | $ | (48.91 | ) | $ | (53.34 | ) | |||
Realized natural gas liquids sales price per Bbl (excluding cash settlements of derivatives)(1)(2) | $ | 37.41 | $ | 41.88 | $ | 45.11 | ||||||
Realized natural gas liquids sales price per Bbl (including cash settlements of derivatives)(1)(2) | $ | 37.41 | $ | 41.88 | $ | 45.11 | ||||||
Average natural gas sales prices: | ||||||||||||
NYMEX-Henry Hub natural gas price per MMBtu | $ | 4.39 | $ | 4.29 | $ | 4.48 | ||||||
Differential to NYMEX-Henry Hub natural gas | $ | (0.22 | ) | $ | (0.22 | ) | $ | (0.05 | ) | |||
Realized natural gas sales price per Mcf (excluding cash settlements of derivatives) | $ | 4.17 | $ | 4.07 | $ | 4.43 | ||||||
Realized natural gas sales price per Mcf (including cash settlements of derivatives)(1)(2) | $ | 4.17 | $ | 4.07 | $ | 4.79 | ||||||
Total combined price (per Mcfe, excluding cash settlements of derivatives) | $ | 4.62 | $ | 4.63 | $ | 4.99 | ||||||
Total combined price (per Mcfe, including cash settlements of derivatives)(1)(2) | $ | 4.62 | $ | 4.63 | $ | 5.32 |
(1) | Average NYMEX futures prices for 2012 as reported on July 29, 2011. For a description of the effect of lower spot prices on cash available for distribution, please read “— Sensitivity Analysis — Commodity Price Changes.” | |
(2) | Our pro forma realized prices do not include gains and losses on commodity derivative instruments. Because the commodity derivative contracts to be contributed to us have been commingled with the properties retained by our predecessor, the pro forma information associated with these commodity derivative contracts is not available by product type. We have given effect to the expected contribution to us at the closing of this offering of commodity derivative contracts covering 64% of our total forecasted production for the twelve months ending September 30, 2012. |
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Operating Area | MMBtu per Mcf | |||
South Texas | 1.045 | |||
East Texas | 1.026 | |||
Weighted Average | 1.039 |
Oil | Natural Gas | |||||||||||
Operating Area | Per Bbl | Per MMBtu | Per Mcf | |||||||||
South Texas | $ | (5.08 | ) | $ | (0.14 | ) | $ | 0.06 | ||||
East Texas | $ | (3.96 | ) | $ | (0.39 | ) | $ | (0.28 | ) | |||
Weighted Average | $ | (4.27 | ) | $ | (0.22 | ) | $ | (0.05 | ) |
Puts | Collars | Swaps | ||||||||||||||||||||||||||
Weighted Average | ||||||||||||||||||||||||||||
Weighted | Price | Weighted | ||||||||||||||||||||||||||
Average | Floor | Ceiling | Average | |||||||||||||||||||||||||
Oil (October 1, 2011 — September 30, 2012) | Bbl | Price | Bbl | Price | Price | Bbl | Price | |||||||||||||||||||||
NYMEX — WTI | 1,800 | $ | 85.00 | 54,900 | $ | 86.56 | $ | 114.72 | — | — | ||||||||||||||||||
% of forecasted oil production | 2 | % | 55 | % | ||||||||||||||||||||||||
% of total forecasted oil production | 57 | % |
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Puts | Collars | Swaps | ||||||||||||||||||||||||||
Weighted Average | ||||||||||||||||||||||||||||
Weighted | Price | Weighted | ||||||||||||||||||||||||||
Average | Floor | Ceiling | Average | |||||||||||||||||||||||||
NGL (October 1, 2011 — September 30, 2012): | Bbl | Price | Bbl | Price | Price | Bbl | Price | |||||||||||||||||||||
Mt. Belvieu Propane | — | — | 14,400 | $ | 52.50 | $ | 66.78 | — | — | |||||||||||||||||||
Mt. Belvieu Butane | — | — | 7,200 | $ | 71.40 | $ | 86.10 | — | — | |||||||||||||||||||
Mt. Belvieu Isobutane | — | — | 4,800 | $ | 71.40 | $ | 89.04 | — | — | |||||||||||||||||||
Mt. Belvieu Gasoline | — | — | 19,200 | $ | 94.50 | $ | 117.60 | — | — | |||||||||||||||||||
Total NGL Hedges | — | — | 45,600 | $ | 75.16 | $ | 93.57 | — | — | |||||||||||||||||||
% of forecasted NGL production | 24 | % | ||||||||||||||||||||||||||
% of total forecasted NGL production | 24 | % |
Puts | Collars | Swaps | ||||||||||||||||||||||||||
Weighted | Weighted Average Price | Weighted | ||||||||||||||||||||||||||
Average | Floor | Ceiling | Average | |||||||||||||||||||||||||
Natural Gas (October 1, 2011 — September 30, 2012): | MMBtu | Price | MMBtu | Price | Price | MMBtu | Price | |||||||||||||||||||||
NYMEX — Henry Hub | 12,000 | $ | 4.50 | 2,481,000 | $ | 4.98 | $ | 5.73 | 189,000 | $ | 4.83 | |||||||||||||||||
TETCO South Texas Basis | 1,380,000 | $ | 4.53 | 2,190,000 | $ | 4.78 | $ | 6.17 | 660,000 | $ | 5.61 | |||||||||||||||||
NGPL TexOk Basis | — | — | 927,000 | $ | 5.41 | $ | 6.46 | 450,000 | $ | 6.23 | ||||||||||||||||||
Houston Ship Channel Basis | — | — | 1,590,000 | $ | 4.28 | $ | 5.65 | 960,000 | $ | 4.84 | ||||||||||||||||||
Total Natural Gas Hedges | 1,392,000 | $ | 4.53 | 7,188,000 | $ | 4.82 | $ | 5.94 | 2,259,000 | $ | 5.34 | |||||||||||||||||
% of forecasted natural gas production | 9 | % | 44 | % | 14 | % | ||||||||||||||||||||||
% of total forecasted natural gas production | 67 | % |
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Forecasted | ||||||||||||
Pro Forma | Pro Forma | Twelve Months | ||||||||||
Year Ended | Twelve Months | Ending | ||||||||||
December 31, | Ended | September 30, | ||||||||||
2010 | June 30, 2011 | 2012 | ||||||||||
(Unaudited) | ||||||||||||
($ in millions) | ||||||||||||
Oil: | ||||||||||||
Oil revenues | $ | 7.9 | $ | 8.5 | $ | 9.4 | ||||||
Oil derivative contracts gain (loss)(1) | — | — | (0.1 | ) | ||||||||
Total | $ | 7.9 | $ | 8.5 | $ | 9.3 | ||||||
NGLs: | ||||||||||||
NGLs revenues | $ | 10.2 | $ | 10.0 | $ | 8.4 | ||||||
NGLs derivative contracts gain (loss)(1) | — | — | — | |||||||||
Total | $ | 10.2 | $ | 10.0 | $ | 8.4 | ||||||
Natural gas: | ||||||||||||
Natural gas revenues | $ | 69.7 | $ | 66.0 | $ | 72.0 | ||||||
Natural gas derivative contracts gain (loss)(1) | — | — | 5.9 | |||||||||
Total | $ | 69.7 | $ | 66.0 | $ | 77.9 | ||||||
Total: | ||||||||||||
Operating Revenues | $ | 87.8 | $ | 84.5 | $ | 89.8 | ||||||
Commodity derivative contracts gain (loss)(1) | — | — | 5.8 | |||||||||
Operating revenue and realized commodity derivative contract gains | $ | 87.8 | $ | 84.5 | $ | 95.6 | ||||||
(1) | Our pro forma realized prices do not include gains or losses on commodity derivative contracts. Because the commodity derivative contracts to be contributed to us have been commingled with the properties retained by our predecessor, the pro forma information associated with these commodity derivative contracts is not available by product type. We have given effect to the expected contribution to us at the closing of this offering of commodity derivative contracts covering 64% of our total forecasted production for the twelve months ending September 30, 2012. |
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Forecasted | |||||||||||||||
Pro Forma | Pro Forma | Twelve Months | |||||||||||||
Year Ended | Twelve Months | Ending | |||||||||||||
December 31, | Ended | September 30, | |||||||||||||
2010 | June 30, 2011 | 2012 | |||||||||||||
Lease operating expenses (in millions) | $ | 23 | .1 | $ | 25 | .0 | $ | 18 | .3 | ||||||
Less: Ad valorem taxes (in millions) | (1 | .6) | (2 | .0) | — | ||||||||||
Lease operating expenses excluding ad valorem taxes (in millions) | 21 | .5 | 23 | .0 | 18 | .3 | |||||||||
Lease operating expenses (per Mcfe) | $ | 1 | .13 | $ | 1 | .26 | $ | 1 | .02 |
Pro Forma | Forecasted | |||||||||||
Pro Forma | Twelve Months | Twelve Months | ||||||||||
Year Ended | Ended | Ending | ||||||||||
December 31, 2010 | June 30, 2011 | September 30, 2012 | ||||||||||
($ in millions) | ||||||||||||
Oil, natural gas and NGL revenues, excluding the effect of our commodity derivative contracts | $ | 87.8 | $ | 84.5 | $ | 89.8 | ||||||
Production taxes | $ | 7.4 | $ | 6.8 | $ | 6.1 | ||||||
Ad valorem taxes | $ | 1.6 | $ | 2.0 | $ | 2.2 | ||||||
Production and ad valorem taxes | $ | 9.0 | $ | 8.8 | $ | 8.3 | ||||||
Production and ad valorem taxes as a percentage of revenue | 10.2 | % | 10.4 | % | 9.2 | % |
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• | There will not be any new federal, state or local regulation of portions of the energy industry in which we operate, or an interpretation of existing regulation, that will be materially adverse to our business; | |
• | There will not be any major adverse change in commodity prices or the energy industry in general; | |
• | Market, insurance and overall economic conditions will not change substantially; and | |
• | We will not undertake any extraordinary transactions that would materially affect our cash flow. |
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Percentage of Forecasted Net Production | ||||||||||||
90% | 100% | 110% | ||||||||||
(In millions, except per unit amounts) | ||||||||||||
Forecasted net production: | ||||||||||||
Oil (MBbl) | 89.6 | 99.5 | 109.5 | |||||||||
NGLs (MBbl) | 167.7 | 186.3 | 204.9 | |||||||||
Natural gas (MMcf) | 14,635.4 | 16,261.6 | 17,887.7 | |||||||||
Total (MMcfe) | 16,178.8 | 17,976.4 | 19,774.0 | |||||||||
Oil (Bbl/d) | 244.7 | 271.9 | 299.1 | |||||||||
NGLs (Bbl/d) | 458.1 | 509.0 | 559.9 | |||||||||
Natural gas (Mcf/d) | 39,987.4 | 44,430.5 | 48,873.5 | |||||||||
Total (Mcfe/d) | 44,204.2 | 49,115.8 | 54,027.4 |
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Percentage of Forecasted Net Production | ||||||||||||
90% | 100% | 110% | ||||||||||
(In millions, except per unit amounts) | ||||||||||||
Forecasted prices: | ||||||||||||
NYMEX-WTI oil price (per Bbl) | $ | 98.45 | $ | 98.45 | $ | 98.45 | ||||||
Realized oil price (per Bbl) (excluding derivatives) | $ | 94.18 | $ | 94.18 | $ | 94.18 | ||||||
Realized oil price (per Bbl) (including derivatives) | $ | 93.61 | $ | 93.67 | $ | 93.71 | ||||||
NYMEX-WTI oil price (per Bbl) | $ | 98.45 | $ | 98.45 | $ | 98.45 | ||||||
Realized natural gas liquids price (per Bbl) (excluding derivatives) | $ | 45.11 | $ | 45.11 | $ | 45.11 | ||||||
Realized natural gas liquids price (per Bbl) (including derivatives) | $ | 45.11 | $ | 45.11 | $ | 45.11 | ||||||
NYMEX-Henry Hub natural gas price (per MMBtu) | $ | 4.48 | $ | 4.48 | $ | 4.48 | ||||||
Realized natural gas price (per Mcf) (excluding derivatives) | $ | 4.43 | $ | 4.43 | $ | 4.43 | ||||||
Realized natural gas price (per Mcf) (including derivatives) | $ | 4.83 | $ | 4.79 | $ | 4.76 | ||||||
Forecasted Adjusted EBITDA projection: | ||||||||||||
Operating revenue | $ | 80.8 | $ | 89.8 | $ | 98.7 | ||||||
Realized derivative gains (losses) | 5.8 | 5.8 | 5.8 | |||||||||
Total revenue and realized derivative gains (losses) | $ | 86.6 | $ | 95.6 | $ | 104.5 | ||||||
Oil and natural gas production expenses | (16.5 | ) | (18.3 | ) | (20.2 | ) | ||||||
Production and ad valorem taxes | (7.7 | ) | (8.3 | ) | (8.9 | ) | ||||||
General and administrative expenses | (5.0 | ) | (5.0 | ) | (5.0 | ) | ||||||
Estimated Adjusted EBITDA | $ | 57.4 | $ | 64.0 | $ | 70.4 | ||||||
Minimum estimated Adjusted EBITDA | ||||||||||||
Excess cash available for distribution | $ | $ | $ |
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(In millions of dollars, except per unit amounts) | ||||||||||||||||
NYMEX-Henry Hub natural gas price (per MMBtu): | $ | 4.25 | $ | 4.50 | $ | 4.75 | $ | 5.00 | ||||||||
NYMEX-WTI oil price (per Bbl): | $ | 90.00 | $ | 100.00 | $ | 110.00 | $ | 120.00 | ||||||||
Forecasted net production: | ||||||||||||||||
Oil (MBbl) | 99.5 | 99.5 | 99.5 | 99.5 | ||||||||||||
NGLs (MBbl) | 186.3 | 186.3 | 186.3 | 186.3 | ||||||||||||
Natural gas (MMcf) | 16,261.6 | 16,261.6 | 16,261.6 | 16,261.6 | ||||||||||||
Total (MMcfe) | 17,976.4 | 17,976.4 | 17,976.4 | 17,976.4 | ||||||||||||
Oil (Bbl/d) | 271.9 | 271.9 | 271.9 | 271.9 | ||||||||||||
NGLs (Bbl/d) | 509.0 | 509.0 | 509.0 | 509.0 | ||||||||||||
Natural gas (Mcf/d) | 44,430.5 | 44,430.5 | 44,430.5 | 44,430.5 | ||||||||||||
Total (Mcfe/d) | 49,115.8 | 49,115.8 | 49,115.8 | 49,115.8 | ||||||||||||
Forecasted prices: | ||||||||||||||||
NYMEX-WTI oil price (per Bbl) | $ | 90.00 | $ | 100.00 | $ | 110.00 | $ | 120.00 | ||||||||
Realized oil price (per Bbl) (excluding derivatives) | $ | 85.73 | $ | 95.73 | $ | 105.73 | $ | 115.73 | ||||||||
Realized oil price (per Bbl) (including derivatives) | $ | 85.70 | $ | 95.09 | $ | 103.93 | $ | 112.08 | ||||||||
NYMEX-WTI oil price (per Bbl) | $ | 90.00 | $ | 100.00 | $ | 110.00 | $ | 120.00 | ||||||||
Realized natural gas liquids price (per Bbl) (excluding derivatives) | $ | 41.23 | $ | 45.81 | $ | 50.39 | $ | 54.97 | ||||||||
Realized natural gas liquids price (per Bbl) (including derivatives) | $ | 41.61 | $ | 45.81 | $ | 50.17 | $ | 53.37 | ||||||||
NYMEX-Henry Hub natural gas price (per MMBtu) | $ | 4.25 | $ | 4.50 | $ | 4.75 | $ | 5.00 | ||||||||
Realized natural gas price (per Mcf) (excluding derivatives) | $ | 4.20 | $ | 4.44 | $ | 4.69 | $ | 4.94 | ||||||||
Realized natural gas price (per Mcf) (including derivatives) | $ | 4.69 | $ | 4.79 | $ | 4.92 | $ | 5.05 | ||||||||
Forecasted Adjusted EBITDA projection: | ||||||||||||||||
Operating revenue | $ | 84.4 | $ | 90.3 | $ | 96.2 | $ | 102.0 | ||||||||
Realized derivative gains (losses) | 8.7 | 5.6 | 3.5 | 1.3 | ||||||||||||
Total revenue and realized derivative gains (losses) | $ | 93.1 | $ | 95.9 | $ | 99.7 | $ | 103.3 | ||||||||
Oil and natural gas production expenses | (18.3 | ) | (18.3 | ) | (18.3 | ) | (18.3 | ) | ||||||||
Production and ad valorem taxes | (7.9 | ) | (8.3 | ) | (8.7 | ) | (9.1 | ) | ||||||||
General and administrative expenses | (5.0 | ) | (5.0 | ) | (5.0 | ) | (5.0 | ) | ||||||||
Estimated Adjusted EBITDA | $ | 61.9 | $ | 64.3 | $ | 67.7 | $ | 70.9 | ||||||||
Minimum estimated Adjusted EBITDA | ||||||||||||||||
Excess cash available for distribution | $ | $ | $ | $ |
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• | less, the amount of cash reserves established by our general partner at the date of determination of available cash for the quarter to: |
• | provide for the proper conduct of our business, which could include, but is not limited to, amounts reserved for capital expenditures, working capital and operating expenses; | |
• | comply with applicable law, any of our debt instruments or other agreements; or | |
• | provide funds for distributions to our unitholders (including our general partner) for any one or more of the next four quarters (provided that our general partner may not establish cash reserves for future distributions on our common and subordinated units unless it determines that the establishment of reserves will not prevent us from distributing the minimum quarterly distribution on all common units and any cumulative arrearages on such common units for such quarter); |
• | plus, if our general partner so determines, all or a portion of cash on hand on the date of determination of available cash for the quarter resulting from borrowing (including working capital borrowings) made after the end of the quarter. |
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• | $ million (as described below);plus | |
• | all of our cash receipts after the closing of this offering, excluding cash from interim capital transactions, which include the following: |
• | borrowings (including sales of debt securities) that are not working capital borrowings; | |
• | sales of equity interests; and | |
• | sales or other dispositions of assets outside the ordinary course of business; |
• | working capital borrowings made after the end of the period but on or before the date of determination of operating surplus for the period;plus | |
• | cash distributions paid (including incremental incentive distributions) on equity issued to finance all or a portion of the construction, replacement, acquisition, development or improvement of a capital |
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improvement or replacement of a capital asset (such as reserves or equipment) in respect of the period beginning on the date that we enter into a binding obligation to commence the construction, replacement, acquisition, development or improvement of a capital improvement, construction, replacement, acquisition, development or improvement of a capital asset and ending on the earlier to occur of the date the capital improvement or capital asset begins producing in paying quantities or is placed into service, as applicable, and the date that it is abandoned or disposed of;plus |
• | cash distributions paid (including incremental incentive distributions) on equity issued to pay the construction period interest on debt incurred (including periodic net payments under related interest rate swap arrangements), or to pay construction period distributions on equity issued, to finance the capital improvements or capital assets referred to above;less | |
• | all of our operating expenditures (as described below) after the closing of this offering and the completion of the formation transactions;less | |
• | the amount of cash reserves established by our general partner to provide funds for future operating expenditures;less | |
• | all working capital borrowings not repaid within twelve months after having been incurred, or repaid within such twelve month period with the proceeds of additional working capital borrowings;less | |
• | any cash loss realized on disposition of an investment capital expenditure. |
• | repayment of working capital borrowings previously deducted from operating surplus pursuant to the provision described in the penultimate bullet point of the description of operating surplus above when such repayment actually occurs; | |
• | payments (including prepayments and prepayment penalties) of principal of and premium on indebtedness, other than working capital borrowings; |
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• | growth capital expenditures; | |
• | actual maintenance capital expenditures (as discussed in further detail below); | |
• | investment capital expenditures; | |
• | payment of transaction expenses relating to interim capital transactions; | |
• | distributions to our partners; or | |
• | repurchases of equity interests except to fund obligations under employee benefit plans. |
• | borrowings (including sales of debt securities) other than working capital borrowings; | |
• | sales of our equity interests; and | |
• | sales or other dispositions of assets outside the ordinary course of business. |
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• | it will reduce the risk that maintenance capital expenditures in any one quarter will be large enough to render operating surplus less than the minimum quarterly distribution to be paid on all the units for the quarter; | |
• | it will increase our ability to distribute as operating surplus cash we receive from non-operating sources; | |
• | in quarters where estimated maintenance capital expenditures exceed actual maintenance capital expenditures, it will be more difficult for us to raise our distribution above the minimum quarterly distribution, because the amount of estimated maintenance capital expenditures will reduce the amount of cash available for distribution to our unitholders, even in quarters where there are no corresponding actual capital expenditures; conversely, the use of estimated maintenance capital expenditures in calculating operating surplus will have the opposite effect for quarters in which actual maintenance capital expenditures exceed our estimated maintenance capital expenditures; and | |
• | it will reduce the likelihood that a large maintenance capital expenditure during a particular quarter will prevent our general partner’s affiliates from being able to convert some or all of their subordinated units to common units since the effect of an estimate is to spread the expected expense over several periods, thereby mitigating the effect of the actual payment of the expenditure on any single period. |
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• | Distributions of available cash from operating surplus on each of the outstanding common units, subordinated units and general partner units and any other partnership interests that are senior or equal in right of distribution to the subordinated units equaled or exceeded, in the aggregate, the sum of the minimum quarterly distributions payable with respect to a period of twelve consecutive quarters immediately preceding such date; |
• | The “adjusted operating surplus” (as defined below) generated during the period of twelve consecutive quarters immediately preceding that date equaled or exceeded, in the aggregate, the sum of the minimum quarterly distributions on all of the outstanding common units, subordinated units and general partner units and any other partnership interests that are senior or equal in right of distribution to the subordinated units that were outstanding during these periods payable with respect to such period on a fully diluted basis; and |
• | there are no arrearages in payment of the minimum quarterly distribution on the common units. |
• | distributions of available cash from operating surplus on each of the outstanding common units, subordinated units and general partner units and any other partnership interests that are senior or equal |
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in right of distribution to the subordinated units equaled or exceeded $ (125% of the annualized minimum quarterly distribution) for the four quarter period immediately preceding that date; |
• | the “adjusted operating surplus” generated during the four-quarter period immediately preceding that date equaled or exceeded the sum of a distribution of $ (125% of the annualized minimum quarterly distribution) on all of the outstanding common units, subordinated units and general partner units and any other partnership interests that are senior or equal in right of distribution to the subordinated units, in each case that were outstanding during such four quarter period on a fully diluted weighted average basis, and the corresponding distributions on the incentive distribution rights; and |
• | there are no arrearages in payment of the minimum quarterly distribution on the common units. |
• | the subordination period will end and each subordinated unit will immediately convert into one common unit; | |
• | any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and | |
• | our general partner will have the right to convert its general partner units into common units or to receive cash in exchange for such general partner units at the equivalent common unit fair market value. |
• | operating surplus generated with respect to that period (excluding any amounts attributable to the items described in the first bullet point under “— Operating Surplus and Capital Surplus — Operating Surplus”);less | |
• | any net increase in working capital borrowings with respect to that period;less | |
• | any net decrease in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period;plus | |
• | any net decrease in working capital borrowings with respect to that period;plus | |
• | any net increase in cash reserves for operating expenditures with respect to that period required by any debt instrument for the repayment of principal, interest or premium;plus | |
• | any net decrease made in subsequent periods in cash reserves for operating expenditures initially established with respect to such period to the extent such decrease results in a reduction of adjusted operating surplus in subsequent periods pursuant to the third bullet point above. |
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• | first, 99.9% to the common unitholders, pro rata, and 0.1% to our general partner, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter; | |
• | second, 99.9% to the common unitholders, pro rata, and 0.1% to our general partner, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period; | |
• | third, 99.9% to the subordinated unitholders, pro rata, and 0.1% to our general partner, until we distribute for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and | |
• | thereafter, in the manner described in “— General Partner Interest and Incentive Distribution Rights” below. |
• | first, 99.9% to all unitholders, pro rata, and 0.1% to our general partner, until we distribute for each outstanding unit an amount equal to the minimum quarterly distribution for that quarter; and | |
• | thereafter, in the manner described in “— General Partner Interest and Incentive Distribution Rights” below. |
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• | we have distributed available cash from operating surplus to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and | |
• | we have distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution; |
• | first, 99.9% to all unitholders, pro rata, and 0.1% to our general partner, until each unitholder receives a total of $ per unit for that quarter (the “first target distribution”); | |
• | second, 85.0% to all unitholders, pro rata, and 15.0% to our general partner, until each unitholder receives a total of $ per unit for that quarter (the “second target distribution”); and | |
• | thereafter, 75.0% to all unitholders, pro rata, and 25.0% to our general partner. |
Total Quarterly | Marginal Percentage Interest in Distributions | |||||||||||
Distribution per Unit | Unitholders | General Partner | ||||||||||
Minimum Quarterly Distribution | $ | 99.9 | % | 0.1 | % | |||||||
First Target Distribution | above $ | up to $ | 99.9 | % | 0.1 | % | ||||||
Second Target Distribution | above $ | up to $ | 85.0 | % | 15.0 | % | ||||||
Thereafter | above $ | 75.0 | % | 25.0 | % |
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• | first, 99.9% to all unitholders, pro rata, and 0.1% to our general partner, until each unitholder receives an amount equal to 115% of the reset minimum quarterly distribution for that quarter; | |
• | second, 85.0% to all unitholders, pro rata, and 15.0% to our general partner, until each unitholder receives an amount per unit equal to 125% of the reset minimum quarterly distribution for the quarter; and | |
• | thereafter, 75.0% to all unitholders, pro rata, and 25.0% to our general partner. |
Quarterly | Marginal Percentage Interest in | Quarterly Distribution per | ||||||||||||
Distribution per Unit | Distributions | Unit Following Hypothetical | ||||||||||||
Prior to Reset | Unitholders | General Partner | Reset | |||||||||||
Minimum quarterly distribution | $ | 99.9 | % | 0.1 | % | $ | ||||||||
First target distribution | up to $ | 99.9 | % | 0.1 | % | up to $ (1) | ||||||||
Second target distribution | above $ up to $ | 85.0 | % | 15.0 | % | above $ (1) up to $ (2) | ||||||||
Thereafter | above $ | 75.0 | % | 25.0 | % | above $ (2) |
(1) | This amount is 115.0% of the hypothetical reset minimum quarterly distribution. | |
(2) | This amount is 125.0% of the hypothetical reset minimum quarterly distribution. |
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Cash | ||||||||||||||||||||||||||||
Quarterly | Distributions to | Cash Distributions to General Partner Prior to Reset | ||||||||||||||||||||||||||
Distribution per | Common | Incentive | ||||||||||||||||||||||||||
Unit Prior to | Unitholders | Common | 0.1% General | Distribution | Total | |||||||||||||||||||||||
Reset | Prior to Reset | Units | Partner Interest | Rights | Total | Distributions | ||||||||||||||||||||||
Minimum quarterly distribution | $ | $ | $ | — | $ | $ | — | $ | $ | |||||||||||||||||||
First target distribution | up to $ | — | ||||||||||||||||||||||||||
Second target distribution | above $ up to $ | — | ||||||||||||||||||||||||||
Thereafter | above $ | — | ||||||||||||||||||||||||||
$ | $ | — | $ | $ | $ | $ | ||||||||||||||||||||||
Cash | ||||||||||||||||||||||||||||
Quarterly | Distributions to | Cash Distributions to General Partner After Reset | ||||||||||||||||||||||||||
Distribution per | Common | Incentive | ||||||||||||||||||||||||||
Unit Prior to | Unitholders | Common | 0.1% General | Distribution | Total | |||||||||||||||||||||||
Reset | Prior to Reset | Units | Partner Interest | Rights | Total | Distributions | ||||||||||||||||||||||
Minimum quarterly distribution | $ | $ | $ | $ | $ | — | $ | $ | ||||||||||||||||||||
First target distribution | up to $ | — | — | — | — | — | — | |||||||||||||||||||||
Second target distribution | above $ up to $ | — | — | — | — | — | — | |||||||||||||||||||||
Thereafter | above $ | — | — | — | — | — | — | |||||||||||||||||||||
$ | $ | $ | $ | — | $ | $ | ||||||||||||||||||||||
• | First, 99.9% to all unitholders, pro rata, and 0.1% to our general partner, until the minimum quarterly distribution is reduced to zero, as described below; |
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• | Second, 99.9% to the common unitholders, pro rata, and 0.1% to our general partner, until we distribute for each common unit, an amount of available cash from capital surplus equal to any unpaid arrearages in payment of the minimum quarterly distribution on the common units; and | |
• | Thereafter, we will make all distributions of available cash from capital surplus as if they were from operating surplus. |
• | the minimum quarterly distribution; | |
• | target distribution levels; | |
• | the unrecovered initial unit price; and | |
• | the number of common units into which a subordinated unit is convertible. |
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• | first, to our general partner and the holders of units who have negative balances in their capital accounts to the extent of and in proportion to those negative balances; | |
• | second, 99.9% to the common unitholders, pro rata, and 0.1% to our general partner, until the capital account for each common unit is equal to the sum of: (1) the unrecovered initial unit price; (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs; and (3) any unpaid arrearages in payment of the minimum quarterly distribution; | |
• | third, 99.9% to the subordinated unitholders, pro rata, and 0.1% to our general partner, until the capital account for each subordinated unit is equal to the sum of: (1) the unrecovered initial unit price; and (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs; | |
• | fourth, 99.9% to all unitholders, pro rata, and 0.1% to our general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the first target distribution per unit over the minimum quarterly distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the minimum quarterly distribution per unit that we distributed 99.9% to the unitholders, pro rata, and 0.1% to our general partner, for each quarter of our existence; |
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• | fifth, 85.0% to all unitholders, pro rata, and 15.0% to our general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the second target distribution per unit over the first target distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the first target distribution per unit that we distributed 85.0% to the unitholders, pro rata, and 15.0% to our general partner for each quarter of our existence; and | |
• | thereafter, 75.0% to all unitholders, pro rata, and 25.0% to our general partner. |
• | first, 99.9% to holders of subordinated units in proportion to the positive balances in their capital accounts and 0.1% to our general partner, until the capital accounts of the subordinated unitholders have been reduced to zero; | |
• | second, 99.9% to the holders of common units in proportion to the positive balances in their capital accounts and 0.1% to our general partner, until the capital accounts of the common unitholders have been reduced to zero; and | |
• | thereafter, 100.0% to our general partner. |
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• | adjustments to reflect the acquisitions of oil and natural gas properties consummated in June 2010, April 2011, and May 2011 by our predecessor; |
• | the contribution by Memorial Resource and certain of its subsidiaries, including our predecessor, to us of the Partnership Properties in exchange for common units, subordinated units and $ million in cash (based on the midpoint of the price range set forth on the cover page of this prospectus), and the issuance to our general partner of general partner units, representing a 0.1% general partner interest in us, and all of our incentive distribution rights; |
• | the issuance and sale by us to the public of common units in this offering and the application of the net proceeds as described in “Use of Proceeds”; and |
• | our borrowing of approximately $130.0 million under our new $ million revolving credit facility and the application of the net proceeds as described in “Use of Proceeds.” |
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Memorial Production | ||||||||||||||||||||||||||||||||||||
Partners LP | ||||||||||||||||||||||||||||||||||||
Pro Forma | ||||||||||||||||||||||||||||||||||||
Six | ||||||||||||||||||||||||||||||||||||
Our Predecessor | Year | Months | ||||||||||||||||||||||||||||||||||
Six Months Ended | Ended | Ended | ||||||||||||||||||||||||||||||||||
Year Ended December 31, | June 30, | December 31, | June 30, | |||||||||||||||||||||||||||||||||
2006 | 2007 | 2008 | 2009 | 2010 | 2010 | 2011 | 2010 | 2011 | ||||||||||||||||||||||||||||
(Unaudited) | (Unaudited) | (Unaudited) | ||||||||||||||||||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||||||||||||||
Statement of Operations Data: | ||||||||||||||||||||||||||||||||||||
Revenues | ||||||||||||||||||||||||||||||||||||
Oil and natural gas sales | $ | 112 | $ | 11,949 | $ | 49,313 | $ | 24,541 | $ | 37,308 | $ | 14,813 | $ | 31,973 | $ | 87,762 | $ | 43,902 | ||||||||||||||||||
Other income | 21 | 153 | 622 | 319 | 1,433 | 1,314 | 252 | 1,404 | 244 | |||||||||||||||||||||||||||
Total revenues | 133 | 12,102 | 49,935 | 24,860 | 38,741 | 16,127 | 32,225 | 89,166 | 44,146 | |||||||||||||||||||||||||||
Costs and expenses: | ||||||||||||||||||||||||||||||||||||
Lease operating | 156 | 2,873 | 8,843 | 11,207 | 13,974 | 5,205 | 11,116 | 23,052 | 12,893 | |||||||||||||||||||||||||||
Exploration | — | — | 374 | 2,690 | 39 | — | 56 | 36 | — | |||||||||||||||||||||||||||
Production taxes | 7 | 1,113 | 3,127 | 1,464 | 2,112 | 967 | 2,084 | 7,387 | 3,525 | |||||||||||||||||||||||||||
Depreciation, depletion and amortization | 233 | 18,144 | 12,353 | 15,226 | 20,066 | 8,173 | 10,759 | 34,772 | 14,577 | |||||||||||||||||||||||||||
Impairment of proved oil and natural gas properties | 1,430 | — | 14,166 | 3,480 | 11,800 | 3,319 | 2,893 | 9,509 | — | |||||||||||||||||||||||||||
General and administrative | 1,390 | 2,937 | 3,835 | 4,811 | 6,116 | 2,271 | 3,604 | 5,819 | 3,479 | |||||||||||||||||||||||||||
Accretion | 1 | 319 | 224 | 320 | �� | 663 | 251 | 466 | 1,072 | 534 | ||||||||||||||||||||||||||
(Gain) loss on derivative instruments | — | 734 | (9,815 | ) | (10,834 | ) | (10,264 | ) | (6,254 | ) | (1,987 | ) | (10,264 | ) | (1,987 | ) | ||||||||||||||||||||
Gain on sale of properties | — | — | (7,395 | ) | (7,851 | ) | (1 | ) | — | (62,729 | ) | — | (62,721 | ) | ||||||||||||||||||||||
Other, net | (508 | ) | 744 | — | 304 | 890 | 891 | 772 | 890 | 772 | ||||||||||||||||||||||||||
Total costs and expenses | 2,709 | 26,864 | 25,712 | 20,817 | 45,395 | 14,823 | (32,966 | ) | 72,273 | (28,928 | ) | |||||||||||||||||||||||||
Operating income (loss) | (2,576 | ) | (14,762 | ) | 24,223 | 4,043 | (6,654 | ) | 1,304 | 65,191 | 16,893 | 73,074 | ||||||||||||||||||||||||
Interest expense | (7 | ) | (1,135 | ) | (3,138 | ) | (2,937 | ) | (4,438 | ) | (1,828 | ) | (3,241 | ) | (4,105 | ) | (2,053 | ) | ||||||||||||||||||
Income (loss) before income taxes | (2,583 | ) | (15,897 | ) | 21,085 | 1,106 | (11,092 | ) | (524 | ) | 61,950 | 12,788 | 71,021 | |||||||||||||||||||||||
Income tax expense | — | — | — | — | (225 | ) | — | (122 | ) | (225 | ) | (122 | ) | |||||||||||||||||||||||
Net income (loss) | $ | (2,583 | ) | $ | (15,897 | ) | $ | 21,085 | $ | 1,106 | $ | (11,317 | ) | $ | (524 | ) | $ | 61,828 | $ | 12,563 | $ | 70,899 | ||||||||||||||
Cash Flow Data: | ||||||||||||||||||||||||||||||||||||
Net cash provided by operating activities | $ | (1,282 | ) | $ | 6,742 | $ | 32,838 | $ | 12,672 | $ | 20,288 | $ | 15,463 | $ | 8,336 | |||||||||||||||||||||
Net cash (used in) investing activities | (6,538 | ) | (97,416 | ) | (45,547 | ) | (24,947 | ) | (116,687 | ) | (100,273 | ) | (154,461 | ) | ||||||||||||||||||||||
Net cash provided by financing activities | 8,500 | 93,196 | 11,619 | 15,989 | 96,756 | 85,986 | 142,848 | |||||||||||||||||||||||||||||
Other Financial Data: | ||||||||||||||||||||||||||||||||||||
Adjusted EBITDA | $ | 33,644 | $ | 24,953 | $ | 23,833 | $ | 11,049 | $ | 17,705 | $ | 60,202 | $ | 26,533 |
Memorial | ||||||||||||||||||||||||||||
Production | ||||||||||||||||||||||||||||
Partners LP | ||||||||||||||||||||||||||||
Our Predecessor | Pro Forma | |||||||||||||||||||||||||||
As of | As of | |||||||||||||||||||||||||||
Year Ended December 31, | June 30, | June 30, | ||||||||||||||||||||||||||
2006 | 2007 | 2008 | 2009 | 2010 | 2011 | 2011 | ||||||||||||||||||||||
(Unaudited) | (Unaudited) | |||||||||||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||||||
Balance Sheet Data: | ||||||||||||||||||||||||||||
Working capital (deficit) | $ | 1,107 | $ | (1,684 | ) | $ | (966 | ) | $ | 9,494 | $ | 4,116 | $ | 9,356 | $ | 4,364 | ||||||||||||
Total assets | 6,565 | 99,021 | 145,529 | 146,153 | 248,540 | 457,646 | 426,056 | |||||||||||||||||||||
Total debt | 3,500 | 46,726 | 62,536 | 61,784 | 115,428 | 206,372 | 130,000 | |||||||||||||||||||||
Partners’ capital | 2,416 | 36,488 | 54,576 | 72,988 | 105,801 | 220,435 | 280,694 |
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FINANCIAL CONDITION AND RESULTS OF OPERATIONS
• | a discussion of our business on a pro forma basis, including: |
• | a general overview of our properties; | |
• | our results of operations; | |
• | our liquidity and capital resources; and | |
• | our quantitative and qualitative disclosures about market risk; and |
• | a discussion of our predecessor’s business on a historical basis, including: |
• | our predecessor’s results of operations; | |
• | our predecessor’s liquidity and capital resources; and | |
• | our predecessor’s quantitative and qualitative disclosures about market risk. |
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• | production volumes; | |
• | realized prices on the sale of oil and natural gas, including the effect of our derivative contracts; | |
• | lease operating expenses; | |
• | general and administrative expenses; and | |
• | Adjusted EBITDA. |
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Year Ending December 31, | ||||||||||||||||||||
2011 | 2012 | 2013 | 2014 | 2015 | ||||||||||||||||
Natural Gas Derivative Contracts: | ||||||||||||||||||||
Swap contracts: | ||||||||||||||||||||
Volume (MMBtu/d) | 5,682 | 6,164 | 4,932 | — | — | |||||||||||||||
Weighted-average fixed price | $ | 5.37 | $ | 5.32 | $ | 5.24 | $ | — | $ | — | ||||||||||
Collar contracts: | ||||||||||||||||||||
Volume (MMBtu/d) | 12,225 | 20,311 | 19,463 | 3,945 | 2,630 | |||||||||||||||
Weighted-average ceiling price | $ | 6.27 | $ | 5.91 | $ | 5.83 | $ | 6.31 | $ | 6.75 | ||||||||||
Weighted-average floor price | $ | 5.02 | $ | 4.79 | $ | 4.75 | $ | 5.08 | $ | 5.25 | ||||||||||
Put options: | ||||||||||||||||||||
Volume (MMBtu/d) | 8,285 | 2,295 | — | — | — | |||||||||||||||
Weighted-average floor price | $ | 4.30 | $ | 4.80 | $ | — | $ | — | $ | — | ||||||||||
Total natural gas volumes hedged (MMBtu/d): | 26,192 | 28,770 | 24,395 | 3,945 | 2,630 | |||||||||||||||
Oil Derivative Contracts: | ||||||||||||||||||||
Collar contracts: | ||||||||||||||||||||
Volume (Bbl/d) | 114 | 148 | 156 | 105 | — | |||||||||||||||
Weighted-average ceiling price | $ | 110.87 | $ | 115.12 | $ | 116.94 | $ | 117.72 | $ | — | ||||||||||
Weighted-average floor price | $ | 84.81 | $ | 86.67 | $ | 87.16 | $ | 90.00 | $ | — | ||||||||||
Put options: | ||||||||||||||||||||
Volume (Bbl/d) | 10 | — | — | — | — | |||||||||||||||
Weighted-average floor price | $ | 85.00 | $ | — | $ | — | $ | — | $ | — | ||||||||||
Natural Gas Liquids Derivative Contracts: | ||||||||||||||||||||
Collar contracts: | ||||||||||||||||||||
Volume (Bbl/d) | 62 | 125 | — | — | — | |||||||||||||||
Weighted-average ceiling price | $ | 93.57 | $ | 93.57 | $ | — | $ | — | $ | — | ||||||||||
Weighted-average floor price | $ | 75.16 | $ | 75.16 | $ | — | $ | — | $ | — |
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• | Plus: |
• | Interest expense, including realized and unrealized losses on interest rate derivative contracts; | |
• | Income tax expense; | |
• | Depreciation, depletion and amortization; | |
• | Impairment of goodwill and long-lived assets (including oil and natural gas properties); | |
• | Accretion of asset retirement obligations; | |
• | Unrealized losses on commodity derivative contracts; | |
• | Losses on sale of assets and other, net; | |
• | Unit-based compensation expenses; | |
• | Exploration costs; | |
• | Acquisition related costs; and |
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• | Other non-routine items that we deem appropriate. |
• | Less: |
• | Interest income; | |
• | Income tax benefit; | |
• | Unrealized gains on commodity derivative contracts; | |
• | Gains on sale of assets and other, net; and | |
• | Other non-routine items that we deem appropriate. |
• | our operating performance as compared to that of other companies and partnerships in our industry, without regard to financing methods, capital structure or historical cost basis; and | |
• | the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness, and make distributions on our units. |
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Our Predecessor | Memorial Production Partners LP Pro Forma | |||||||||||||||||||||||||||
Six | Six | |||||||||||||||||||||||||||
Months | Months | |||||||||||||||||||||||||||
Ended | Year Ended | Ended | ||||||||||||||||||||||||||
Year Ended December 31, | June 30, | December 31, | June 30, | |||||||||||||||||||||||||
2008 | 2009 | 2010 | 2010 | 2011 | 2010 | 2011 | ||||||||||||||||||||||
(Unaudited) | (Unaudited) | |||||||||||||||||||||||||||
Revenues (in thousands): | ||||||||||||||||||||||||||||
Oil and natural gas sales | $ | 49,313 | $ | 24,541 | $ | 37,308 | $ | 14,813 | $ | 31,973 | $ | 87,762 | $ | 43,902 | ||||||||||||||
Other income | 622 | 319 | 1,433 | 1,314 | 252 | 1,404 | 244 | |||||||||||||||||||||
Total revenues | $ | 49,935 | $ | 24,860 | $ | 38,741 | $ | 16,127 | $ | 32,225 | $ | 89,166 | $ | 44,146 | ||||||||||||||
Costs and expenses (in thousands): | ||||||||||||||||||||||||||||
Lease operating | 8,843 | 11,207 | 13,974 | 5,205 | 11,116 | 23,052 | 12,893 | |||||||||||||||||||||
Exploration | 374 | 2,690 | 39 | — | 56 | 36 | — | |||||||||||||||||||||
Production taxes | 3,127 | 1,464 | 2,112 | 967 | 2,084 | 7,387 | 3,525 | |||||||||||||||||||||
Depreciation, depletion and amortization | 12,353 | 15,226 | 20,066 | 8,173 | 10,759 | 34,772 | 14,577 | |||||||||||||||||||||
Impairment of proved oil and natural gas properties | 14,166 | 3,480 | 11,800 | 3,319 | 2,893 | 9,509 | — | |||||||||||||||||||||
General and administrative | 3,835 | 4,811 | 6,116 | 2,271 | 3,604 | 5,819 | 3,479 | |||||||||||||||||||||
Accretion | 224 | 320 | 663 | 251 | 466 | 1,072 | 534 | |||||||||||||||||||||
(Gain) loss on derivative instruments | (9,815 | ) | (10,834 | ) | (10,264 | ) | (6,254 | ) | (1,987 | ) | (10,264 | ) | (1,987 | ) | ||||||||||||||
Gain on sale of properties | (7,395 | ) | (7,851 | ) | (1 | ) | — | (62,729 | ) | — | (62,721 | ) | ||||||||||||||||
Other, net | — | 304 | 890 | 891 | 772 | 890 | 772 | |||||||||||||||||||||
Total costs and expenses | 25,712 | 20,817 | 45,395 | 14,823 | (32,966 | ) | 72,273 | (28,928 | ) | |||||||||||||||||||
Operating income (loss) | 24,223 | 4,043 | (6,654 | ) | 1,304 | 65,191 | 16,893 | 73,074 | ||||||||||||||||||||
Interest expense | (3,138 | ) | (2,937 | ) | (4,438 | ) | (1,828 | ) | (3,241 | ) | (4,105 | ) | (2,053 | ) | ||||||||||||||
Income (loss) before income taxes | 21,085 | 1,106 | (11,092 | ) | (524 | ) | 61,950 | 12,788 | 71,021 | |||||||||||||||||||
Income tax expense | — | — | (225 | ) | — | (122 | ) | (225 | ) | (122 | ) | |||||||||||||||||
Net income (loss) | $ | 21,085 | $ | 1,106 | $ | (11,317 | ) | $ | (524 | ) | $ | 61,828 | $ | 12,563 | $ | 70,899 | ||||||||||||
Oil and natural gas revenue (in thousands): | ||||||||||||||||||||||||||||
Oil sales | $ | 5,886 | $ | 3,521 | $ | 3,438 | $ | 1,620 | $ | 3,480 | $ | 7,933 | $ | 4,703 | ||||||||||||||
NGL sales | 1,559 | 924 | 1,404 | 750 | 2,924 | 10,177 | 5,502 | |||||||||||||||||||||
Natural gas sales | 41,868 | 20,096 | 32,466 | 12,443 | 25,569 | 69,652 | 33,697 | |||||||||||||||||||||
Total oil and natural gas revenue | $ | 49,313 | $ | 24,541 | $ | 37,308 | $ | 14,813 | $ | 31,973 | $ | 87,762 | $ | 43,902 | ||||||||||||||
Production: | ||||||||||||||||||||||||||||
Oil (MBbls) | 59 | 61 | 45 | 22 | 36 | 107 | 50 | |||||||||||||||||||||
NGLs (MBbls) | 37 | 33 | 34 | 18 | 55 | 272 | 114 | |||||||||||||||||||||
Natural gas (MMcf) | 4,719 | 5,282 | 7,314 | 2,583 | 5,669 | 16,713 | 7,903 | |||||||||||||||||||||
Total (MMcfe) | 5,295 | 5,847 | 7,792 | 2,819 | 6,217 | 18,985 | 8,888 | |||||||||||||||||||||
Average net production (MMcfe/d) | 15.2 | 16.0 | 21.3 | 15.6 | 34.3 | 52.0 | 49.1 | |||||||||||||||||||||
Average sales price: | ||||||||||||||||||||||||||||
Oil (per Bbl) | $ | 100.58 | $ | 58.01 | $ | 75.81 | $ | 74.18 | $ | 96.74 | $ | 74.35 | $ | 94.90 | ||||||||||||||
NGLs (per Bbl) | $ | 41.65 | $ | 27.61 | $ | 41.02 | $ | 42.73 | $ | 52.90 | $ | 37.41 | $ | 48.05 | ||||||||||||||
Natural gas (per Mcf) | $ | 8.87 | $ | 3.80 | $ | 4.44 | $ | 4.82 | $ | 4.51 | $ | 4.17 | $ | 4.26 | ||||||||||||||
Total (per Mcfe) | $ | 9.31 | $ | 4.20 | $ | 4.79 | $ | 5.25 | $ | 5.14 | $ | 4.62 | $ | 4.94 | ||||||||||||||
Average unit costs per Mcfe: | ||||||||||||||||||||||||||||
Lease operating expenses | $ | 1.67 | $ | 1.92 | $ | 1.79 | $ | 1.84 | $ | 1.79 | $ | 1.21 | $ | 1.45 | ||||||||||||||
Production taxes | $ | 0.59 | $ | 0.25 | $ | 0.27 | $ | 0.34 | $ | 0.34 | $ | 0.39 | $ | 0.40 | ||||||||||||||
General and administrative expenses | $ | 0.72 | $ | 0.82 | $ | 0.78 | $ | 0.81 | $ | 0.58 | $ | 0.31 | $ | 0.39 | ||||||||||||||
Depreciation, depletion and amortization | $ | 2.33 | $ | 2.60 | $ | 2.58 | $ | 2.90 | $ | 1.73 | $ | 1.83 | $ | 1.64 |
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• | Our predecessor completed its acquisition of certain properties from Forest Oil in June 2010. The estimated proved reserves associated with and the results of operations from those acquired assets were not included in our predecessor’s results of operations prior to the date of acquisition. Our predecessor exchanged certain of the Forest Oil properties with BP in May 2011; the remainder of the Forest Oil properties acquired by our predecessor are included in the Partnership Properties and represent 50 Bcfe, or approximately 15% of our pro forma total estimated proved reserves, as of December 31, 2010. |
• | Our predecessor completed its acquisition of certain properties from BP in May 2011. The estimated proved reserves associated with and the results of operations from those acquired assets were not included in our predecessor’s historical results of operations through May 31, 2011. The BP America properties acquired by our predecessor are included in the Partnership Properties and represent 47 Bcfe, or approximately 15% of our pro forma total estimated proved reserves, as of December 31, 2010. | |
• | The Partnership Properties will include property interests contributed to us by WHT, all of which property interests were acquired by WHT in April 2011. Those properties being contributed represent 113 Bcfe, or approximately 35% of our pro forma total estimated proved reserves, as of December 31, 2010. | |
• | Our predecessor pays a management fee to the Funds pursuant to its operating agreement. We are not obligated to pay such a management fee, and therefore our pro forma results of operations are not directly comparable to our predecessor’s with respect to this fee. | |
• | Our predecessor uses commodity derivative contracts to manage price fluctuations. Upon the closing of this offering, we will enter into derivative contracts to manage price fluctuations and our predecessor will contribute to us certain commodity derivative contracts entered into in connection with its ownership of the Partnership Properties, which will not comprise all commodity derivative contracts entered into by our predecessor. |
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• | The following significant acquisitions by our predecessor: |
• | The Forest Oil asset acquisition in June 2010 for approximately $65.9 million. | |
• | Two separate acquisitions of assets in East Texas in January and March 2010, respectively, for a net purchase price of approximately $14 million. |
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• | Two separate acquisitions of assets in South Texas in April and May 2010, respectively, for a total purchase price of approximately $23.2 million. |
• | Oil and natural gas properties and related assets acquired from BP in May 2011, including the related disposition to BP of certain assets previously acquired from Forest Oil. |
• | 40% of the oil and natural gas properties and related assets acquired by WHT from a third party in April 2011. |
• | The sale of certain non-core oil and natural gas properties located in South Texas in 2009 and 2008 for $11.8 million and $15.4 million, respectively. |
Six Months Ended June 30, | ||||||||
2010 | 2011 | |||||||
Revenues (in thousands): | ||||||||
Oil and natural gas sales | $ | 14,813 | $ | 31,973 | ||||
Other income | 1,314 | 252 | ||||||
Total revenues | 16,127 | 32,225 | ||||||
Costs and expenses (in thousands): | ||||||||
Lease operating | 5,205 | 11,116 | ||||||
Exploration | — | 56 | ||||||
Production taxes | 967 | 2,084 | ||||||
Depreciation, depletion and amortization | 8,173 | 10,759 | ||||||
Impairment of proved oil and natural gas properties | 3,319 | 2,893 | ||||||
General and administrative | 2,271 | 3,604 | ||||||
Accretion | 251 | 466 | ||||||
(Gain) loss on derivative instruments | (6,254 | ) | (1,987 | ) | ||||
Gain on sale of properties | — | (62,729 | ) | |||||
Other, net | 891 | 772 | ||||||
Total costs and expenses | 14,823 | (32,966 | ) | |||||
Operating income (loss) | 1,304 | 65,191 | ||||||
Interest expense | (1,828 | ) | (3,241 | ) | ||||
Income (loss) before income taxes | (524 | ) | 61,950 | |||||
Income tax expense | — | (122 | ) | |||||
Net income (loss) | $ | (524 | ) | $ | 61,828 | |||
Production: | ||||||||
Oil (MBbls) | 22 | 36 | ||||||
NGLs (MBbls) | 18 | 55 | ||||||
Natural gas (MMcf) | 2,583 | 5,669 | ||||||
Total (MMcfe) | 2,819 | 6,217 | ||||||
Average net production (MMcfe/d) | 15.7 | 34.3 | ||||||
Average sales price: | ||||||||
Oil (per Bbl) | $ | 74.18 | $ | 96.74 | ||||
NGLs (per Bbl) | $ | 42.73 | $ | 52.90 | ||||
Natural gas (per Mcf) | $ | 4.82 | $ | 4.51 | ||||
Total (per Mcfe) | $ | 5.25 | $ | 5.14 |
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Six Months Ended June 30, | ||||||||
2010 | 2011 | |||||||
Average unit costs per Mcfe: | ||||||||
Lease operating expenses | $ | 1.84 | $ | 1.79 | ||||
Production taxes | $ | 0.34 | $ | 0.34 | ||||
Depreciation, depletion and amortization | $ | 2.90 | $ | 1.73 | ||||
Impairment of proved oil and natural gas properties | $ | 1.18 | $ | 0.47 | ||||
General and administrative expenses | $ | 0.81 | $ | 0.58 |
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Year Ended December 31, | ||||||||
2009 | 2010 | |||||||
Revenues (in thousands): | ||||||||
Oil and natural gas sales | $ | 24,541 | $ | 37,308 | ||||
Other income | 319 | 1,433 | ||||||
Total revenues | 24,860 | 38,741 | ||||||
Costs and expenses (in thousands): | ||||||||
Lease operating | 11,207 | 13,974 | ||||||
Exploration | 2,690 | 39 | ||||||
Production taxes | 1,464 | 2,112 | ||||||
Depreciation, depletion and amortization | 15,226 | 20,066 | ||||||
Impairment of proved oil and natural gas properties | 3,480 | 11,800 | ||||||
General and administrative | 4,811 | 6,116 | ||||||
Accretion | 320 | 663 | ||||||
(Gain) loss on derivative instruments | (10,834 | ) | (10,264 | ) | ||||
Gain on sale of properties | (7,851 | ) | (1 | ) | ||||
Other, net | 304 | 890 | ||||||
Total costs and expenses | 20,817 | 45,395 | ||||||
Operating income (loss) | 4,043 | (6,654 | ) | |||||
Interest expense | (2,937 | ) | (4,438 | ) | ||||
Income (loss) before taxes | 1,106 | (11,092 | ) | |||||
Income tax expense | — | (225 | ) | |||||
Net income (loss) | $ | 1,106 | $ | (11,317 | ) | |||
Production: | ||||||||
Oil (MBbls) | 61 | 45 | ||||||
NGLs (MBbls) | 33 | 34 | ||||||
Natural gas (MMcf) | 5,282 | 7,314 | ||||||
Total (MMcfe) | 5,847 | 7,792 | ||||||
Average net production (MMcfe/d) | 16 | 21 | ||||||
Average sales price: | ||||||||
Oil (per Bbl) | $ | 58.01 | $ | 75.81 | ||||
NGLs (per Bbl) | $ | 27.61 | $ | 41.02 | ||||
Natural gas (per Mcf) | $ | 3.80 | $ | 4.44 | ||||
Total (per Mcfe) | $ | 4.20 | $ | 4.79 | ||||
Average unit cost per Mcfe: | ||||||||
Lease operating expenses | $ | 1.92 | $ | 1.79 | ||||
Production taxes | $ | 0.25 | $ | 0.27 | ||||
Depreciation, depletion and amortization | $ | 2.60 | $ | 2.58 | ||||
Impairment of proved oil and natural gas properties | $ | 0.60 | $ | 1.51 | ||||
General and administrative expenses | $ | 0.82 | $ | 0.78 |
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Year Ended December 31, | ||||||||
2008 | 2009 | |||||||
Revenues (in thousands): | ||||||||
Oil and natural gas sales | $ | 49,313 | $ | 24,541 | ||||
Other income | 622 | 319 | ||||||
Total revenues | 49,935 | 24,860 | ||||||
Costs and expenses (in thousands): | ||||||||
Lease operating | 8,843 | 11,207 | ||||||
Exploration | 374 | 2,690 | ||||||
Production taxes | 3,127 | 1,464 | ||||||
Depreciation, depletion and amortization | 12,353 | 15,226 | ||||||
Impairment of proved oil and natural gas properties | 14,166 | 3,480 | ||||||
General and administrative | 3,835 | 4,811 | ||||||
Accretion | 224 | 320 | ||||||
(Gain) loss on derivative instruments | (9,815 | ) | (10,834 | ) | ||||
Gain on sale of properties | (7,395 | ) | (7,851 | ) | ||||
Other, net | — | 304 | ||||||
Total costs and expenses | 25,712 | 20,817 | ||||||
Operating income (loss) | 24,223 | 4,043 | ||||||
Interest expense | (3,138 | ) | (2,937 | ) | ||||
Income tax expense | — | — | ||||||
Net income (loss) | $ | 21,085 | $ | 1,106 | ||||
Production: | ||||||||
Oil (MBbls) | 59 | 61 | ||||||
NGLs (MBbls) | 37 | 33 | ||||||
Natural gas (MMcf) | 4,719 | 5,282 | ||||||
Total (MMcfe) | 5,295 | 5,847 | ||||||
Average net production (MMcfe/d) | 15 | 16 | ||||||
Average sales price: | ||||||||
Oil (per Bbl) | $ | 100.58 | $ | 58.01 | ||||
NGLs (per Bbl) | $ | 41.65 | $ | 27.61 | ||||
Natural gas (per Mcf) | $ | 8.87 | $ | 3.80 | ||||
Total (per Mcfe) | $ | 9.31 | $ | 4.20 | ||||
Average unit costs per Mcfe: | ||||||||
Lease operating expenses | $ | 1.67 | $ | 1.92 | ||||
Production taxes | $ | 0.59 | $ | 0.25 | ||||
Depreciation, depletion and amortization | $ | 2.33 | $ | 2.60 | ||||
Impairment of proved oil and natural gas properties | $ | 2.68 | $ | 0.60 | ||||
General and administrative expenses | $ | 0.72 | $ | 0.82 |
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Year Ended December 31, | Six Months Ended June 30, | |||||||||||||||||||
2008 | 2009 | 2010 | 2010 | 2011 | ||||||||||||||||
Net cash provided by operating activities | $ | 32,838 | $ | 12,672 | $ | 20,288 | $ | 15,463 | $ | 8,336 | ||||||||||
Net cash used in investing activities | (45,547 | ) | (24,947 | ) | (116,687 | ) | (100,273 | ) | (154,461 | ) | ||||||||||
Net cash provided by financing activities | 11,619 | 15,989 | 96,756 | 85,986 | 142,848 | |||||||||||||||
Net (decrease) increase in cash | (1,090 | ) | 3,714 | 357 | 1,176 | (3,277 | ) |
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Natural Gas Swaps | ||||||||
Weighted Average | ||||||||
Year | ($/MMBtu) | MMBtu/d | ||||||
2011 | $ | 5.698 | 3,633 | |||||
2012 | $ | 5.794 | 3,049 | |||||
2013 | $ | 5.767 | 2,005 |
Natural Gas Collars | ||||||||||||
Weighted Average Floor | Weighted Average Ceiling | |||||||||||
Year | ($/MMBtu) | ($/MMBtu) | MMBtu/d | |||||||||
2011 | $ | 5.305 | $ | 6.761 | 6,542 | |||||||
2012 | $ | 4.897 | $ | 6.177 | 9,016 | |||||||
2013 | $ | 4.778 | $ | 5.790 | 11,474 |
Natural Gas Put Options | ||||||||
Year | Floor Price ($/MMBtu) | MMBtu/d | ||||||
2011 | $ | 4.300 | 8,219 | |||||
2012 | $ | 4.800 | 2,295 |
Oil Collars | ||||||||||||
Weighted Average Floor | Weighted Average Ceiling | |||||||||||
Year | ($/MMBtu) | ($/MMBtu) | Bbl/d | |||||||||
2011 | $ | 75.00 | $ | 94.00 | 39 | |||||||
2012 | $ | 73.33 | $ | 94.97 | 30 | |||||||
2013 | $ | 72.00 | $ | 103.68 | 25 |
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Payments Due by Period | ||||||||||||||||||||
Less Than | More Than | |||||||||||||||||||
Contractual Obligation | Total | One Year | 2-3 Years | 4-5 Years | 5 Years | |||||||||||||||
Revolving credit facility | $ | 115,222 | $ | — | $ | — | $ | 115,222 | $ | — | ||||||||||
Operating lease | 938 | 297 | 418 | 223 | — | |||||||||||||||
Capital lease | 59 | 29 | 30 | — | — | |||||||||||||||
Other borrowings | 222 | — | 138 | 84 | — | |||||||||||||||
Interest expense on long-term debt | 12,364 | 2,718 | 4,823 | 4,823 | — | |||||||||||||||
Total contractual obligations | $ | 128,805 | $ | 3,044 | $ | 5,409 | $ | 120,352 | $ | — | ||||||||||
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• | institute a more comprehensive compliance function; | |
• | design, establish, evaluate and maintain a system of internal controls over financial reporting in compliance with the requirements of Section 404 of the Sarbanes-Oxley Act of 2002 and the related rules and regulations of the SEC and the Public Company Accounting Oversight Board; | |
• | comply with rules promulgated by NASDAQ; | |
• | prepare and distribute periodic public reports in compliance with our obligations under the federal securities laws; | |
• | establish new internal policies, such as those relating to disclosure controls and procedures and insider trading; | |
• | involve and retain to a greater degree outside counsel and accountants in the above activities; and | |
• | establish an investor relations function. |
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Estimated Pro Forma | Average Net | Average | ||||||||||||||||||||||||||||||
Net Proved Reserves | Pro Forma | Reserve-to- | Producing | |||||||||||||||||||||||||||||
% Natural | % Proved | Production | Production | Wells | ||||||||||||||||||||||||||||
Bcfe | Gas | Developed | MMcfe/d | % | Ratio(1) | Gross | Net | |||||||||||||||||||||||||
(Years) | ||||||||||||||||||||||||||||||||
South Texas | 172.2 | 98 | % | 87 | % | 32 | 61 | % | 15 | 563 | 424 | |||||||||||||||||||||
East Texas | 152.5 | 76 | % | 76 | % | 20 | 39 | % | 21 | 727 | 185 | |||||||||||||||||||||
Total | 324.7 | 88 | % | 81 | % | 52 | 100 | % | 17 | 1,290 | 609 | |||||||||||||||||||||
(1) | The averagereserve-to-production ratio is calculated by dividing estimated pro forma net proved reserves as of December 31, 2010 by average pro forma net production for the year ended December 31, 2010. |
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Estimated Pro Forma | Average Net | Average | ||||||||||||||||||||||||||||||
Net Proved Reserves(1) | Pro Forma | Reserve-to- | �� | |||||||||||||||||||||||||||||
% Natural | % Proved | Production | Production | Producing Wells | ||||||||||||||||||||||||||||
Bcfe | Gas | Developed | MMcfe/d | % | Ratio(2) | Gross | Net | |||||||||||||||||||||||||
(Years) | ||||||||||||||||||||||||||||||||
East Texas(3) | 760.6 | 84 | % | 30 | % | 43 | 64 | % | 48 | 1,067 | 306 | |||||||||||||||||||||
North Louisiana | 224.7 | 73 | % | 44 | % | 18 | 27 | % | 35 | 267 | 172 | |||||||||||||||||||||
Rockies | 51.0 | 67 | % | 41 | % | 6 | 9 | % | 25 | 123 | 85 | |||||||||||||||||||||
Total | 1,036.3 | 81 | % | 34 | % | 67 | 100 | % | 43 | 1,457 | 563 | |||||||||||||||||||||
(1) | Memorial Resource’s estimated pro forma net proved reserves are (i) based primarily on reserve reports prepared by third-party independent petroleum engineers and (ii) exclusive of our estimated pro forma net proved reserves. | |
(2) | The averagereserve-to-production ratio is calculated by dividing estimated pro forma net proved reserves as of December 31, 2010 by average pro forma net production for the year ended December 31, 2010. | |
(3) | Includes properties in which we have a joint interest. Memorial Resource’s portions of these properties included 169 Bcfe of reserves as of December 31, 2010 and 20 MMcfe/d of average net pro forma production for the year ended December 31, 2010 associated with properties acquired by WHT in April 2011. Please read “Summary — Our Partnership Structure and Formation Transactions — Background Information Regarding Our Predecessor and the Partnership Properties.” |
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• | Maintain and Grow a Stable Production Profile through Accretive Acquisitions and Low-Risk Development. Our development plans will target proved drilling locations that are low cost, present minimal risk, and support a stable production profile. We will seek to acquire proved developed properties with long-lived reserves, low production decline rates and identified and predictable development potential. We believe that our management team’s experience positions us to identify, evaluate, execute, integrate and exploit suitable acquisitions. |
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• | Strategically Utilize Our Relationship with Memorial Resource, the Funds, and their Respective Affiliates (Including NGP) to Gain Access to and, from Time to Time, Acquire Producing Oil and Natural Gas Properties that Meet Our Acquisition Criteria. We may have the opportunity to acquire producing oil and natural gas properties directly from Memorial Resource, the Funds, or their respective affiliates from time to time in the future. While none of Memorial Resource, the Funds, or any of their respective affiliates is contractually obligated to offer or sell any properties to us, we believe that selling properties to us will enhance Memorial Resource’s and, accordingly, the Funds’ economic returns by monetizing long-lived producing properties while potentially retaining a portion of the resulting cash flow through distributions on Memorial Resource’s (and the Funds’) limited partner and incentive distribution interests in us. | |
• | Leverage Our Relationships with Memorial Resource, the Funds, and their Respective Affiliates (Including NGP) to Participate in Acquisitions of Third Party Producing Properties and to Increase the Size and Scope of Our Potential Third-Party Acquisition Targets. Memorial Resource was formed in part to acquire and develop oil and natural gas properties, some of which will likely meet our acquisition criteria. In addition, NGP and its affiliates (including the Funds) have long histories of pursuing and consummating oil and natural gas property acquisitions in North America. Through our relationships with Memorial Resource, the Funds, and their respective affiliates (including NGP), we expect that we will have access to their significant pool of management talent and industry relationships, which we believe will provide us a competitive advantage in pursuing potential third-party acquisition opportunities. We may have the opportunity to work jointly with Memorial Resource to pursue certain acquisitions of oil and natural gas properties that may not otherwise be attractive acquisition candidates for any of us individually. For example, we may jointly pursue an acquisition where we would acquire the proved developed portion of the acquired properties and Memorial Resource would acquire the undeveloped portion. We believe this arrangement will give us access to an array of third-party acquisition opportunities that we would not otherwise be in a position to pursue. | |
• | Exploit Opportunities on Our Current Properties and Manage Our Operating Costs and Capital Expenditures. We intend to pursue low-risk drilling of our proved undeveloped inventory and to perform cost-reducing operational enhancements. Pursuant to the omnibus agreement, Memorial Resource will provide us and our general partner with operating, management, and administrative services, which we believe will provide us with significant technical expertise and experience that will allow us to identify and execute cost-reducing exploitation and operational improvements on both our existing properties and new acquisitions. Memorial Resource’s operational control of substantially all of our proved reserves as well as its own, often adjoining or complementary properties, enables direct influence and implementation of cost reduction initiatives. | |
• | Reduce Exposure to Commodity Price Risk and Stabilize Cash Flows Through a Disciplined Commodity Hedging Policy. We intend to maintain a portfolio of commodity derivative contracts covering approximately 65% to 85% of our estimated production from total proved developed producing reserves over athree-to-five year period at any given point in time. These commodity derivative contracts may consist of natural gas, oil and NGL financial swaps and collar contracts and natural gas basis financial swaps. Memorial Resource will contribute to us at the closing of this offering derivative contracts for the three months ending December 31, 2011 and the years ending December 31, 2012, 2013, 2014, and 2015 covering approximately 77%, 75%, 69%, 14% and 8%, respectively, of our estimated production from our total proved developed producing reserves existing as of December 31, 2010, based on our reserve reports. We believe these commodity derivative contracts will allow us to mitigate the impact of oil and natural gas price volatility, thereby increasing the predictability of our cash flow. | |
• | Maintain Reasonable Levels of Indebtedness to Permit us to Opportunistically Finance Acquisitions. We intend to maintain modest levels of indebtedness in relation to our cash flows from operations. We believe our internally generated cash flows and our borrowing capacity under our new revolving credit facility will provide us with the financial flexibility to pursue our acquisition and development strategy in an effective and competitive manner. |
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• | Our Long-Lived Reserves with Significant Production History and Predictable Production Decline Rates. Our pro forma estimated proved reserves as of December 31, 2010 divided by our pro forma average net production for 2010, which we refer to as our reserve to production index, was 17 years. Based on our forecasted daily production which is reflected in our reserve reports, the average estimated decline rate for our existing proved developed producing reserves is approximately 9% for the twelve months ended December 31, 2011, approximately 9% compounded average decline for the subsequent four years and approximately 8% thereafter. Our estimated well life is typically more than 20 years, providing a long history of production that enables better predictability of future production decline rates. |
• | Our Relationships with Memorial Resource, the Funds, and their Respective Affiliates (Including NGP), which we Believe will Provide us with Access to a Portfolio of Additional Oil and Natural Gas Properties that Meet Our Acquisition Criteria. Memorial Resource was formed in part to own and acquire producing properties and to develop properties into mature, long-lived producing assets. After giving effect to the formation transactions, Memorial Resource had (i) total estimated proved reserves of 1,036 Bcfe at December 31, 2010, primarily located in East Texas, North Louisiana and the Rockies, of which approximately 81% were natural gas, and approximately 34% were classified as proved developed reserves, and (ii) interests in over 398,000 gross (173,000 net) acres of undeveloped properties. Based on Memorial Resource’s intention to develop its properties and Memorial Resource’s significant ownership interests in us, we believe we may be able to acquire additional assets from Memorial Resource, the Funds, or their respective affiliates in the future. None of Memorial Resource, the Funds, or any of their respective affiliates will have any obligation to offer or sell properties to us following the consummation of this offering. |
• | Our Management Team’s Extensive Experience in the Acquisition, Development and Integration of Oil and Natural Gas Assets. The members of our management team and Memorial Resource collectively have an average of 21 years of experience in the oil and natural gas industry. John A. Weinzierl, the President, Chief Executive Officer and Chairman of our general partner, has 20 years of oil and natural gas industry experience, a strong commercial and technical background and extensive experience acquiring and managing oil and natural gas properties for NGP. |
• | Our Relationship with Memorial Resource, which Provides us with Extensive Technical Expertise in and Familiarity with Developing and Operating Oil and Natural Gas Assets within Our Core Focus Areas. Through the omnibus agreement with Memorial Resource, we have the operational support of a staff of 52 petroleum professionals, many of whom have significant engineering and geoscience expertise in Southand/or East Texas, which are our current geographical areas of focus. We believe that this technical expertise differentiates us from, and provides us with a competitive advantage over, many of our competitors. We intend to utilize these resources in maximizing our production and ultimate reserve recovery, which could add substantial value to our assets. |
• | Our Relationships with Memorial Resource, the Funds, and their Respective Affiliates (Including NGP), which we Believe will Help us with Access to and in the Evaluation and Execution of Future Acquisitions. We believe that our ability to use the industry relationships and broad expertise of Memorial Resource and NGP in expanding our access to acquisitions and evaluating oil and natural gas assets will expand our opportunities and differentiate us from many of our competitors. Additionally, we expect to have the opportunity to work jointly with Memorial Resource to pursue acquisitions of oil and natural gas properties that we would not otherwise be able to pursue on our own or that may not otherwise be attractive acquisition candidates for any of us individually. | |
• | Our Diverse Distribution of Reserve Value, with 1,290 Gross (609 Net) Producing Wells as of December 31, 2010, None of which Contains Estimated Proved Reserves in Excess of 2% of Our |
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Total Estimated Proved Reserves as of December 31, 2010. The value of our pro forma estimated proved reserves, as approximated by the standardized measure, is spread across a wide subset of our producing wells. Our top 10 wells by value represent 11% of our total standardized measure at December 31, 2010. The value of our pro forma estimated proved reserves, as approximated by the standardized measure, is also widely distributed across our producing fields. No producing field in our pro forma estimated proved reserves represents more than 36% of our standardized measure at December 31, 2010. |
• | Our Inventory of 345 Proved Low-Risk Infill Drilling, Recompletion and Development Opportunities in Our Core Operational Areas. We have a substantial inventory of low risk, proved undeveloped locations. At December 31, 2010, the Partnership Properties included 60 Bcfe of estimated proved undeveloped reserves, and had 70 proved identified low-risk proved drilling locations and 275 proved recompletion and development opportunities. Based on our current asset portfolio, we intend to spend approximately $9.2 million for capital expenditures for the twelve months ending September 30, 2012 based on our reserve reports, which amount spent annually we believe will also enable us to maintain our targeted average net production from our assets of 49 MMcfe/d through December 31, 2015. | |
• | Our Competitive Cost of Capital and Financial Flexibility. Unlike our corporate competitors, we do not expect to be subject to federal income taxation at the entity level. We believe that this attribute should provide us with a lower cost of capital compared to many of our competitors, thereby enhancing our ability to compete for future acquisitions, both individually and jointly with Memorial Resource. We also expect that our ability to issue additional common units and other partnership interests in connection with acquisitions will enhance our financial flexibility. Further, we intend to utilize a modest amount of debt to provide flexibility in our capital structure. |
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Pro Forma Average Net Production for the | ||||||||||||||||||||||||||||
Year Ended December 31, 2010 | Average | |||||||||||||||||||||||||||
Estimated Net Proved Reserves | % of | Reserve-to- | ||||||||||||||||||||||||||
% Proved | % Natural | % of | Total | Production | ||||||||||||||||||||||||
MMcfe | Developed | Gas | Total | (MMcfe/d) | Production | Ratio | ||||||||||||||||||||||
South Texas Fields: | ||||||||||||||||||||||||||||
NE Thompsonville | 32,312 | 85 | % | 100 | % | 19 | % | 7 | 23 | % | 12 | |||||||||||||||||
Laredo | 23,992 | 63 | % | 98 | % | 14 | % | 5 | 16 | % | 12 | |||||||||||||||||
Hubberd | 19,166 | 100 | % | 98 | % | 11 | % | 3 | 9 | % | 18 | |||||||||||||||||
East Seven Sisters | 17,820 | 100 | % | 100 | % | 10 | % | 4 | 12 | % | 13 | |||||||||||||||||
Other | 78,871 | 88 | % | 97 | % | 46 | % | 13 | 40 | % | 18 | |||||||||||||||||
Total South Texas Fields | 172,161 | 87 | % | 98 | % | 100 | % | 32 | 100 | % | 15 | |||||||||||||||||
East Texas Fields: | ||||||||||||||||||||||||||||
Carthage | 117,721 | 68 | % | 72 | % | 77 | % | 12 | 60 | % | 28 | |||||||||||||||||
Joaquin | 18,519 | 100 | % | 99 | % | 12 | % | 7 | 35 | % | 7 | |||||||||||||||||
Other | 16,296 | 100 | % | 81 | % | 11 | % | 1 | 5 | % | 26 | |||||||||||||||||
Total East Texas Fields | 152,536 | 76 | % | 76 | % | 100 | % | 20 | 100 | % | 21 | |||||||||||||||||
All Fields | 324,697 | 81 | % | 88 | % | 100 | % | 52 | 100 | % | 17 | |||||||||||||||||
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• | A reserve audit is an examination of reserve information that is conducted for the purpose of expressing an opinion as to whether such reserve information, in the aggregate, is reasonable and has been presented in conformity with generally accepted petroleum engineering and evaluation principles. | |
• | The estimation of proved reserves is an imprecise science due to the many unknown geologic and reservoir factors that cannot be estimated through sampling techniques. Since reserves are only estimates, they cannot be audited for the purpose of verifying exactness. Instead, reserve information is audited for the purpose of reviewing in sufficient detail the policies, procedures and methods used by a company in estimating its reserves so that the reserve auditors may express an opinion as to whether, in the aggregate, the reserve information furnished by a company is reasonable. | |
• | The methods and procedures used by a company, and the reserve information furnished by a company, must be reviewed in sufficient detail to permit the reserve auditor, in its professional judgment, to express an opinion as to the reasonableness of the reserve information. The auditing procedures require the reserve auditor to prepare its own estimates of reserve information for the audited properties. |
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Partnership | ||||
Properties as of | ||||
December 31, 2010 | ||||
Estimated Proved Reserves | ||||
Oil (MBbls) | 2,002 | |||
NGLs (MBbls) | 4,502 | |||
Natural gas (MMcf) | 285,676 | |||
Total (MMcfe)(1) | 324,697 | |||
Proved developed (MMcfe) | 264,572 | |||
Proved undeveloped (MMcfe) | 60,125 | |||
Proved developed reserves as a percentage of total proved reserves | 81 | % | ||
Standardized measure (in millions)(2)(3) | $ | 359.2 | ||
Oil and Natural Gas Prices(4) | ||||
Oil — WTI Posting (Plains) per Bbl | $ | 75.96 | ||
Natural gas — NYMEX-Henry Hub per MMBtu | $ | 4.38 |
(1) | Determined using a ratio of six Mcf of natural gas to one Bbl of oil, condensate or NGLs based on an approximate energy equivalency. This is an energy content correlation and does not reflect a value or price relationship between the commodities. | |
(2) | Standardized measure is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC without giving effect to non-property related expenses, such as general and administrative expenses, interest and income tax expenses, or to depreciation, depletion and amortization. The future cash flows are discounted using an annual discount rate of 10%. Because we are a limited partnership, we are generally not subject to federal income taxes and thus make no provision for federal income taxes in the calculation of our standardized measure. Standardized measure does not give effect to derivative transactions. We expect to hedge a substantial portion of our future estimated production from total proved producing reserves. For a description of our expected commodity derivative contracts, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Pro Forma Liquidity and Capital Resources — Commodity Derivative Contracts.” | |
(3) | Because we are subject to Texas margin tax, standardized measure was negatively impacted by $5.0 million. | |
(4) | Our estimated net proved reserves and related standardized measure were determined using index prices for oil and natural gas, without giving effect to derivative contracts, held constant throughout the life of the properties. These prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. |
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Memorial Production Partners LP | ||||||||||||||||||||
Our Predecessor | Pro Forma | |||||||||||||||||||
Year Ended | Six Months | |||||||||||||||||||
Year Ended December 31, | December 31, | Ended June 30, | ||||||||||||||||||
2008 | 2009 | 2010 | 2010 | 2011 | ||||||||||||||||
Production and operating data: | ||||||||||||||||||||
Net production volumes: | ||||||||||||||||||||
Oil (MBbls) | 59 | 61 | 45 | 107 | 50 | |||||||||||||||
NGLs (MBbls) | 37 | 33 | 34 | 272 | 114 | |||||||||||||||
Natural gas (MMcf) | 4,719 | 5,282 | 7,314 | 16,713 | 7,903 | |||||||||||||||
Total (MMcfe) | 5,295 | 5,847 | 7,792 | 18,985 | 8,888 | |||||||||||||||
Average net production (MMcfe/d) | 15 | 16 | 21 | 52 | 49 | |||||||||||||||
Average sales price:(1) | ||||||||||||||||||||
Oil (per Bbl) | $ | 100.58 | $ | 58.01 | $ | 75.81 | $ | 74.35 | $ | 94.90 | ||||||||||
NGLs (per Bbl) | $ | 41.65 | $ | 27.61 | $ | 41.02 | $ | 37.41 | $ | 48.05 | ||||||||||
Natural gas (per Mcf) | $ | 8.87 | $ | 3.80 | $ | 4.44 | $ | 4.17 | $ | 4.26 | ||||||||||
Average price per Mcfe | $ | 9.31 | $ | 4.20 | $ | 4.79 | $ | 4.62 | $ | 4.94 | ||||||||||
Average unit costs per Mcfe: | ||||||||||||||||||||
Lease operating expenses | $ | 1.67 | $ | 1.92 | $ | 1.79 | $ | 1.21 | $ | 1.45 | ||||||||||
Production taxes | $ | 0.59 | $ | 0.25 | $ | 0.27 | $ | 0.39 | $ | 0.40 | ||||||||||
General and administrative expenses | $ | 0.72 | $ | 0.82 | $ | 0.78 | $ | 0.31 | $ | 0.39 | ||||||||||
Depreciation, depletion and amortization | $ | 2.33 | $ | 2.60 | $ | 2.58 | $ | 1.83 | $ | 1.64 |
(1) | Prices do not include the effects of derivative cash settlements. |
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Oil | Natural Gas | |||||||||||||||
Gross | Net | Gross | Net | |||||||||||||
Operated | 4 | 3 | 542 | 422 | ||||||||||||
Non-operated | — | — | 36 | 2 | ||||||||||||
Total | 4 | 3 | 578 | 424 | ||||||||||||
Developed Acreage(1) | ||||||||
Gross(2) | Net(3) | |||||||
South Texas(4) | 82,400 | 72,744 | ||||||
East Texas | — | — | ||||||
Total | 82,400 | 72,744 |
(1) | Developed acres are acres spaced or assigned to productive wells or wells capable of production. | |
(2) | A gross acre is an acre in which we own a working interest. The number of gross acres is the total number of acres in which we own a working interest. | |
(3) | A net acre is deemed to exist when the sum of our fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof. | |
(4) | The South Texas developed acreage, which is all held by production, includes acreage subject to infill drilling. The infill acreage allows for additional drilling that equates to 1,800 gross and 1,470 net acres, respectfully, which is included in the following Undeveloped Acreage table. |
Undeveloped Acreage(1) | ||||||||
Gross(2) | Net(3) | |||||||
South Texas(4) | 1,800 | 1,470 | ||||||
East Texas | 12,574 | 4,676 | ||||||
Total | 14,374 | 6,146 |
(1) | Undeveloped acres are acres spaced or assigned to proved undeveloped reserve locations. | |
(2) | A gross acre is an acre in which we own a working interest. The number of gross acres is the total number of acres in which we own a working interest. | |
(3) | A net acre is deemed to exist when the sum of our fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof. | |
(4) | The South Texas undeveloped acreage, which is all held by production, consists entirely of infill drilling locations. These locations are associated with existing proved developed acreage. Thus, the acreage included in this table is also included in the preceding Developed Acreage table. |
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Year Ended December 31, | ||||||||||||||||||||||||
2008 | 2009 | 2010 | ||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
Development wells: | ||||||||||||||||||||||||
Productive | 17.0 | 13.5 | 4.0 | 3.7 | 3.0 | 2.7 | ||||||||||||||||||
Dry | 4.0 | 2.5 | 1.0 | 0.9 | — | — | ||||||||||||||||||
Exploratory wells: | ||||||||||||||||||||||||
Productive | — | — | — | — | — | — | ||||||||||||||||||
Dry | — | — | — | — | — | — | ||||||||||||||||||
Total wells: | ||||||||||||||||||||||||
Productive | 17.0 | 13.5 | 4.0 | 3.7 | 3.0 | 2.7 | ||||||||||||||||||
Dry | 4.0 | 2.5 | 1.0 | 0.9 | — | — | ||||||||||||||||||
Total | 21.0 | 16.0 | 5.0 | 4.6 | 3.0 | 2.7 | ||||||||||||||||||
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• | Commercial general liability; |
• | Primary Umbrella / Excess Liability; |
• | Workers’ compensation and Employer’s Liability; |
• | Control of Well; and |
• | Automobile Liability. |
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• | the location of wells; | |
• | the method of drilling and casing wells; | |
• | the surface use and restoration of properties upon which wells are drilled; | |
• | the plugging and abandoning of wells; and | |
• | notice to surface owners and other third parties. |
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Name | Age | Position with Our General Partner | ||||
John A. Weinzierl | 43 | President, Chief Executive Officer, and Chairman | ||||
Andrew J. Cozby | 44 | Vice President, Finance | ||||
Patrick T. Nguyen | 39 | Chief Accounting Officer | ||||
Gregory M. Robbins | 32 | Treasurer | ||||
Larry R. Forney | 54 | Vice President, Operations and Asset Management | ||||
Jonathan M. Clarkson | 61 | Director Nominee | ||||
Kenneth A. Hersh | 48 | Director | ||||
Scott A. Gieselman | 48 | Director | ||||
Tony R. Weber | 49 | Director |
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BENEFICIAL OWNERS AND MANAGEMENT
• | each person who then will beneficially own more than 5% of the then outstanding common units; | |
• | each director and director nominee of our general partner; | |
• | each named executive officer of our general partner; and | |
• | all directors, director nominees and named executive officers of our general partner as a group. |
Percentage of | ||||||||||||||||||||
Total | ||||||||||||||||||||
Percentage of | Percentage of | Common and | ||||||||||||||||||
Common | Common | Subordinated | Subordinated | Subordinated | ||||||||||||||||
Units to be | Units to be | Units to be | Units to be | Units to be | ||||||||||||||||
Beneficially | Beneficially | Beneficially | Beneficially | Beneficially | ||||||||||||||||
Name of Beneficial Owner(1) | Owned(2) | Owned | Owned | Owned | Owned | |||||||||||||||
Memorial Resource(3) | % | % | % | |||||||||||||||||
Kenneth A. Hersh(4) | % | % | % | |||||||||||||||||
Jonathan M. Clarkson | % | % | % | |||||||||||||||||
Scott A. Gieselman | % | % | % | |||||||||||||||||
Tony R. Weber | % | % | % | |||||||||||||||||
John A. Weinzierl | % | % | % | |||||||||||||||||
Andrew J. Cozby | % | % | % | |||||||||||||||||
Larry R. Forney | % | % | % | |||||||||||||||||
Patrick T. Nguyen | % | % | % | |||||||||||||||||
Gregory M. Robbins | % | % | % | |||||||||||||||||
All named executive officers, directors and director nominees as a group (nine persons) | % | % | % |
(1) | The address for all beneficial owners in this table is 1401 McKinney Street, Suite 1025, Houston, Texas 77010. There are no options, warrants or other rights or obligations outstanding that are currently exercisable or exercisable within 60 days into common or subordinated units. | |
(2) | Does not include any common units that may be purchased in a directed unit program. | |
(3) | Memorial Resource is owned by Natural Gas Partners VIII, L.P. (“NGP VIII”), Natural Gas Partners IX, L.P. (“NGP IX”) and NGP IX Offshore Holdings, L.P. (“NGP IX Offshore”), which also collectively directly own, through non-voting membership interests in our general partner, 50% of the economic interest in our incentive distribution rights. NGP VIII, NGP IX and NGP IX Offshore may be deemed to share voting and dispositive power over the reported securities; thus, each may also be deemed to be the beneficial owner of these securities. Each of NGP VIII, NGP IX and NGP IX Offshore disclaims beneficial ownership of the reported securities in excess of such entity’s respective pecuniary interest in the securities. | |
(4) | G.F.W. Energy VIII, L.P., GFW VIII, L.L.C., G.F.W. Energy IX, L.P. and GFW IX, L.L.C. may be deemed to beneficially own the units held by Memorial Resource that are attributable to NGP VIII, NGP IX and NGP IX Offshore by virtue of GFW VIII, L.L.C. being the sole general partner of G.F.W. Energy VIII, L.P. (which is the general partner of NGP VIII) and GFW IX, L.L.C. being the sole general partner of G.F.W. Energy IX, L.P. (which is the general partner of NGP IX and NGP IX Offshore). Kenneth A. Hersh, one of our general partner’s directors and who is an Authorized Member of each of GFW VIII, L.L.C. and GFW IX, L.L.C., may also be deemed to share the power to vote, or to direct the vote, and to |
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dispose, or to direct the disposition, of those units. Mr. Hersh does not own directly any common units or subordinated units. |
Class A | Class IDR | |||||||
Member | Member | |||||||
Name of Beneficial Owner | Interest(a) | Interest(a) | ||||||
Memorial Resource(b) | 100 | % | — | |||||
Natural Gas Partners VIII, L.P.(c)(d) | — | % | ||||||
Natural Gas Partners IX, L.P.(c)(d) | — | % | ||||||
NGP IX Offshore Holdings, L.P. (c)(d) | — | % |
(a) | Our general partner has two classes of member interests. Memorial Resource owns the voting Class A member interest, and will be entitled to 50% of any cash distributions made or common units issued to our general partner with respect to our general partner’s 0.1% general partner interest in us. NGP VIII, NGP IX and NGP IX Offshore own % , % and %, respectively, of the non-voting Class IDR member interest in our general partner, which entitles them to an aggregate 50% of any cash distributions made or common units issued to our general partner. |
(b) | Our general partner is controlled by Memorial Resource, which is controlled by NGP VIII, NGP IX and NGP IX Offshore. Mr. Hersh will share in distributions made by us with respect to interests held by our general partner in proportion to his pecuniary interests. Mr. Hersh disclaims beneficial ownership of the reported securities in excess of his pecuniary interest in such securities. In addition, our general partner’s other non-independent directors and certain of our general partner’s executive officers have indirect financial interests in Memorial Resource and its affiliates. | |
(c) | NGP VIII, NGP IX and NGP IX Offshore may be deemed to share voting and dispositive power over the reported interests of Memorial Resource; thus, each of NGP VIII, NGP IX and NGP IX Offshore may also be deemed to be the beneficial owner of these interests. Each of NGP VIII, NGP IX and NGP IX Offshore disclaims beneficial ownership of such reported interests in excess of such entity’s respective pecuniary interest in such interests. G.F.W. Energy VIII, L.P., GFW VIII, L.L.C., G.F.W. Energy IX, L.P. and GFW IX, L.L.C. may be deemed to beneficially own the interests owned by Memorial Resource attributable to NGP VIII, NGP IX and NGP IX Offshore and the interests held by NGP VIII, NGP IX and NGP IX Offshore by virtue of GFW VIII, L.L.C. being the sole general partner of G.F.W. Energy VIII, L.P. (which is the general partner of NGP VIII) and GFW IX, L.L.C. being the sole general partner of G.F.W. Energy IX, L.P. (which is the general partner of NGP IX and NGP IX Offshore). Kenneth A. Hersh, one of our general partner’s directors and who is an Authorized Member of each of GFW VIII, L.L.C. and GFW IX, L.L.C., may also be deemed to share the power to vote, or to direct the vote, and to dispose, or to direct the disposition, of the interests held by NGP VII, NGP IX and NGP IX Offshore. Mr. Hersh does not own directly any interests in our general partner. | |
(d) | The address for NGP VIII, NGP IX and NGP IX Offshore is 125 E. John Carpenter Fwy., Suite 600, Irving, Texas 75602. |
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The consideration received by our | • common units; | |
general partner and Memorial Resource | • subordinated units; | |
prior to or in connection with this offering | • general partner units (or general partner units if the underwriters exercise their option to purchase additional common units in full); | |
• all of our incentive distribution rights; and |
• approximately $ million in cash (based on the midpoint of the price range set forth on the cover page of this prospectus). |
Distributions of available cash to our general partner and its affiliates | We will generally make cash distributions 99.9% to our unitholders, including Memorial Resource as the holder of approximately % of our limited partner interests, pro rata and 0.1% to our general partner, assuming it makes any capital contributions necessary to maintain its 0.1% general partner interest in us. In addition, if distributions exceed the minimum quarterly distribution and other higher target distribution levels, our general partner will be entitled to increasing percentages of the distributions, up to a maximum of 25.0% of the distributions above the highest target distribution level, including the general partner’s 0.1% general partner interest. | |
Assuming we have sufficient available cash to pay the full minimum quarterly distribution on all of our outstanding units for four quarters, our general partner would receive an annual distribution of approximately $ million on its general partner units and Memorial Resource would receive an annual distribution of approximately $ million on its common units and subordinated units. | ||
Payments to our general partner and its affiliates | Our general partner will not receive a management fee or other compensation for its management of our partnership, but we will reimburse our general partner for all direct and indirect expenses it |
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incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner and its affiliates in connection with operating our business. Our partnership agreement does not set a limit on the amount of expenses for which our general partner may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our partnership agreement provides that our general partner will determine in good faith the amount of such expenses that are allocable to us. | ||
Withdrawal or removal of our general partner | If our general partner is removed under circumstances where cause exists or withdraws where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the departing general partner’s general partner interest in us and the incentive distribution rights for a cash payment equal to the fair market value of those interests. Under all other circumstances where our general partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase the departing general partner’s general partner interest in us and its incentive distribution rights for their fair market value or to convert such interests into common units. |
Liquidation | Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their respective capital account balances. |
• | Class A — At the closing of this offering, Memorial Resource will own all of the Class A membership interests in our general partner. The Class A membership interests will be the sole voting interests in our general partner and will entitle Memorial Resource, as the Class A member, to all distributions we make to our general partner (including distributions with respect to our general partner’s 0.1% general partner interest in us), other than those distributions payable to the Class IDR members described below. |
• | Class IDR — After the closing of this offering, the Funds will own all of the non-voting, Class IDR membership interests in our general partner. The holders of the Class IDR membership interests will be entitled to receive (i) an aggregate of 50% of all cash received by our general partner from us attributable to distributions related to the incentive distribution rights, (ii) 50% of any common units issued to our general partner in connection with any reset of the incentive distribution levels and (iii) 50% of any cash, securities or other proceeds received by our general partner pursuant to a sale or transfer of the incentive distribution rights. |
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• | our obligation to reimburse Memorial Resource for all expenses incurred by Memorial Resource (or payments made on our behalf) in conjunction with its provision of general and administrative services to us, including, but not limited to, our public company expenses and an allocated portion of the salary and benefits of the executive officers of our general partner and other employees of Memorial Resource who perform services for us or on our behalf; |
• | our obligation to reimburse Memorial Resource for insurance coverage expenses it incurs with respect to our business and operations and with respect to director and officer liability coverage for the officers and directors of our general partner; |
• | our obligation to indemnify Memorial Resource for certain liabilities; |
• | Memorial Resource’s obligation to indemnify us against (i) title defects, (ii) income taxes attributable to pre-closing ownership or operation of the contributed assets, including any income tax liabilities related to the formation transactions occurring on or prior to the closing, (iii) environmental claims, losses and expenses associated with the operation of our business prior to the closing, subject to a maximum indemnification amount of $5,000,000; (iv) all liabilities other than covered environmental liabilities, relating to the operation of the contributed assets prior to the closing that were not disclosed in the most recent pro forma balance sheet included in this prospectus, or incurred in the ordinary course of business thereafter, subject to a maximum indemnification amount of $5,000,000; and (v) all losses arising as a result of the failure to obtain by closing any consent, waiver or permit necessary for us to own and operate the Partnership Properties; and |
• | Neither NGP nor its future affiliated funds or affiliates, including the Funds and Memorial Resource, will be restricted, under either our partnership agreement or the omnibus agreement, from competing with us. NGP, any future affiliated funds and its affiliates will be permitted to compete with us and may acquire or dispose of additional oil and natural gas properties or other assets in the future without any obligation to offer us the opportunity to purchase those assets. |
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• | approved by the conflicts committee, although our general partner is not obligated to seek such approval; | |
• | approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates; | |
• | on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or | |
• | fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us. |
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• | permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its right to reset the target distribution levels of its incentive distribution rights at higher levels and receive, in connection with this reset, common units, the exercise of its limited call right, the exercise of its rights to transfer or vote the units it owns, the exercise of its registration rights and its determination whether or not to consent to any merger or consolidation involving us or to any amendment to the partnership agreement; | |
• | provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as general partner so long as it acted in good faith; | |
• | generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner acting in good faith and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or must be “fair and reasonable” to us, as determined by our general partner in good faith. In determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us; | |
• | provides that our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and | |
• | provides that in resolving conflicts of interest, it will be presumed that in making its decision our general partner’s board of directors or the conflicts committee of our general partner’s board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. |
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• | the making of any expenditures, the lending or borrowing of money, the assumption or guarantee of or other contracting for, indebtedness and other liabilities, the issuance of evidences of indebtedness, including indebtedness that is convertible into our securities, and the incurring of any other obligations; | |
• | the purchase, sale or other acquisition or disposition of our securities, or the issuance of additional options, rights, warrants and unit appreciation rights relating to our securities; | |
• | the mortgage, pledge, encumbrance, hypothecation or exchange of any or all of our assets; | |
• | the negotiation, execution and performance of any contracts, conveyances or other instruments; | |
• | the distribution of our cash; | |
• | the selection and dismissal of employees and agents, outside attorneys, accountants, consultants and contractors and the determination of their compensation and other terms of employment or hiring; | |
• | the maintenance of insurance for our benefit and the benefit of our partners; | |
• | the formation of, or acquisition of an interest in, the contribution of property to, and the making of loans to, any limited or general partnerships, joint ventures, corporations, limited liability companies or other entities; | |
• | the control of any matters affecting our rights and obligations, including the bringing and defending of actions at law or in equity and otherwise engaging in the conduct of litigation, arbitration or mediation and the incurring of legal expense and the settlement of claims and litigation; | |
• | the indemnification of any person against liabilities and contingencies to the extent permitted by law; | |
• | the making of tax, regulatory and other filings or rendering of periodic or other reports to governmental or other agencies having jurisdiction over our business or assets; and | |
• | the entering into of agreements with any of its affiliates to render services to us or to itself in the discharge of its duties as our general partner. |
• | the manner in which our business is operated; | |
• | the amount, nature and timing of asset purchases and sales; | |
• | the amount, nature and timing of our capital expenditures; | |
• | the amount of borrowings; |
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• | the issuance of additional units; and | |
• | the creation, reduction or increase of reserves in any quarter. |
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State-law fiduciary duty standards | Fiduciary duties are generally considered to include an obligation to act in good faith and with due care and loyalty. The duty of care, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner to act for the partnership in the same manner as a prudent person would act on his own behalf. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally prohibit a general partner of a Delaware limited partnership from taking any action or engaging in any transaction where a conflict of interest is present. | |
Rights and remedies of unitholders | The Delaware Act generally provides that a limited partner may institute legal action on behalf of the partnership to recover damages from a third-party where a general partner has refused to institute the action or where an effort to cause a general partner to do so is not likely to succeed. In addition, the statutory or case law of some jurisdictions may permit a limited partner to institute legal action on behalf of himself and all other similarly situated limited partners to recover damages from a general partner for violations of its fiduciary duties to the limited partners. | |
Partnership agreement modified standards | Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that might otherwise raise issues about compliance with fiduciary duties or applicable law. For example, our partnership agreement provides that when our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in “good faith” and will not be subject to any other standard under applicable law. In addition, when our general partner is acting in its individual capacity, as opposed to in its capacity as our general partner, it may act without any fiduciary obligation to us or the unitholders whatsoever. These standards reduce the obligations to which our general partner would otherwise be held. | |
In addition to the other more specific provisions limiting the obligations of our general partner, our partnership agreement further provides that our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners for errors of judgment or for any acts or omissions unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that our general partner or its officers and directors acted in bad faith or engaged in fraud or willful misconduct, or in the case of a criminal matter, acted with the knowledge that such conduct was unlawful. |
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Special Provisions Regarding Affiliate Transactions. Our partnership agreement generally provides that affiliate transactions and resolutions of conflicts of interest that are not approved by vote of unitholders and that are not approved by the conflicts committee of the board of directors of our general partner must be: | ||
• on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or | ||
• “fair and reasonable” to us, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to us). | ||
If our general partner does not seek approval from the conflicts committee and the board of directors of our general partner determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the bullet points above, then it will be presumed that, in making its decision, the board of directors, which may include board members affected by the conflict of interest, acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. These standards reduce the obligations to which our general partner would otherwise be held. |
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• | surety bond premiums to replace lost or stolen certificates or to cover taxes and other governmental charges; | |
• | special charges for services requested by a common unitholder; and | |
• | other similar fees or charges. |
• | represents that the transferee has the capacity, power and authority to become bound by our partnership agreement; | |
• | automatically agrees to be bound by the terms and conditions of our partnership agreement; and | |
• | gives the consents, waivers and approvals contained in our partnership agreement, such as the approval of all transactions and agreements that we are entering into in connection with our formation and this offering. |
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• | with regard to distributions of available cash, please read “Our Cash Distribution Policy and Restrictions on Distributions” and “Provisions of Our Partnership Agreement Relating to Cash Distributions”; | |
• | with regard to the fiduciary duties of our general partner, please read “Conflicts of Interest and Fiduciary Duties”; | |
• | with regard to the transfer of common units, please read “Description of the Common Units — Transfer of Common Units”; and | |
• | with regard to allocations of taxable income, taxable loss and other matters, please read “Material Tax Consequences.” |
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• | during the subordination period, the approval of a majority of the outstanding common units, excluding those common units held by our general partner and its affiliates, and a majority of the outstanding subordinated units, each voting as a separate class; and | |
• | after the subordination period, the approval of a majority of the outstanding common units. |
Issuance of additional units | No approval right. Please read “— Issuance of Additional Securities.” | |
Amendment of the partnership agreement | Certain amendments may be made by our general partner without the approval of the unitholders. Other amendments generally require the approval of a unit majority. Please read “— Amendment of the Partnership Agreement.” | |
Merger of our partnership or the sale of all or substantially all of our assets | Unit majority, in certain circumstances. Please read “— Merger, Consolidation, Conversion, Sale or Other Disposition of Assets.” | |
Dissolution of our partnership | Unit majority. Please read “— Termination and Dissolution.” | |
Continuation of our business upon dissolution | Unit majority. Please read “— Termination and Dissolution.” | |
Withdrawal of our general partner | Prior to , 2021, under most circumstances, the approval of a majority of the common units, excluding common units held by our general partner and its affiliates, is required for the withdrawal of our general partner in a manner that would cause a dissolution of our partnership. Please read ‘‘— Withdrawal or Removal of Our General Partner.” | |
Removal of our general partner | Not less than 662/3% of the outstanding units, including units held by our general partner and its affiliates. Please read “— Withdrawal or Removal of Our General Partner.” | |
Transfer of our general partner interest | Our general partner may transfer without a vote of our unitholders all, but not less than all, of its general partner interest in us to an affiliate or another person (other than an individual) in connection with its merger or consolidation with or into, or sale of all, or substantially all, of its assets, to such person. The approval of a majority of the common units, excluding common units held by our general partner and its affiliates, is required in other circumstances for a transfer of the general partner interest to a |
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third-party prior to , 2021. Please read “— Transfer of General Partner Units.” | ||
Transfer of incentive distribution rights | No approval rights. Please read “— Transfer of Incentive Distribution Rights.” | |
Transfer of ownership interests in our general partner | No approval required. Please read “— Transfer of Ownership Interests in Our General Partner.” |
• | arising out of or relating in any way to the partnership agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of the partnership agreement or the duties, obligations or liabilities among limited partners or of limited partners to us, or the rights or powers of, or restrictions on, the limited partners or us); | |
• | brought in a derivative manner on our behalf; | |
• | asserting a claim of breach of a fiduciary duty owed by any director, officer or other employee of us or our general partner, or owed by our general partner, to us or the limited partners; | |
• | asserting a claim arising pursuant to any provision of the Delaware Act; or | |
• | asserting a claim governed by the internal affairs doctrine, |
• | to remove or replace our general partner; | |
• | to approve some amendments to the partnership agreement; or | |
• | to take other action under the partnership agreement |
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• | enlarge the obligations of any limited partner without its consent, unless approved by at least a majority of the type or class of limited partner interests so affected; or | |
• | enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without the consent of our general partner, which consent may be given or withheld in its sole discretion. |
• | a change in our name, the location of our principal place of business, our registered agent or our registered office; | |
• | the admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement; | |
• | a change that our general partner determines to be necessary or appropriate for us to qualify or to continue our qualification as a limited partnership or other entity in which the limited partners have limited liability under the laws of any state or to ensure that neither we, nor any of our subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes; | |
• | a change in our fiscal year or taxable year and related changes; | |
• | an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or the directors, officers, agents or trustees of our general partner from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisors Act of 1940, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, or ERISA, whether or not substantially similar to plan asset regulations currently applied or proposed; |
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• | an amendment that our general partner determines to be necessary or appropriate for the authorization of additional partnership securities or rights to acquire partnership securities; | |
• | any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone; | |
• | an amendment effected, necessitated or contemplated by a merger agreement that has been approved under the terms of our partnership agreement; | |
• | any amendment that our general partner determines to be necessary or appropriate for the formation by us of, or our investment in, any corporation, partnership or other entity, as otherwise permitted by our partnership agreement; | |
• | any amendment necessary to require our limited partners to provide a statement, certification or other evidence to us regarding whether such limited partner is subject to United States federal income taxation on the income generated by us and to provide for the ability of our general partner to redeem the units of any limited partner who fails to provide such statement, certification or other evidence; | |
• | conversions into, mergers with or conveyances to another limited liability entity that is newly formed and has no assets, liabilities or operations at the time of the conversion, merger or conveyance other than those it receives by way of the conversion, merger or conveyance; or | |
• | any other amendments substantially similar to any of the matters described in the clauses above. |
• | do not adversely affect our limited partners (or any particular class of limited partners) in any material respect; | |
• | are necessary or appropriate to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute; | |
• | are necessary or appropriate to facilitate the trading of our limited partner interests or to comply with any rule, regulation, guideline or requirement of any securities exchange on which our limited partner interests are or will be listed for trading; | |
• | are necessary or appropriate for any action taken by our general partner relating to splits or combinations of units under the provisions of our partnership agreement; or | |
• | are required to effect the intent expressed in this prospectus or the intent of the provisions of the partnership agreement or are otherwise contemplated by our partnership agreement. |
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• | the election of our general partner to dissolve us, if approved by the holders of a unit majority; | |
• | there being no limited partners, unless we are continued without dissolution in accordance with applicable Delaware law; | |
• | the entry of a decree of judicial dissolution of our partnership; or | |
• | the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner other than by reason of a transfer of its general partner interest in us in accordance with our partnership agreement or withdrawal or removal following approval and admission of a successor. |
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• | the action would not result in the loss of limited liability under Delaware law of any limited partner; and | |
• | neither our partnership nor any of our subsidiaries would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue (to the extent not already so treated or taxed). |
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• | the subordination period will end and all outstanding subordinated units will immediately convert into common units on aone-for-one basis; | |
• | any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and | |
• | our general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests based on the fair market value of the interests at the time. |
• | an affiliate of our general partner (other than an individual); or | |
• | another entity as part of the merger or consolidation of our general partner with or into another entity or the transfer by our general partner of all or substantially all of its assets to another entity, |
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• | the highest cash price paid by either of our general partner or any of its affiliates for any limited partner interests of the class purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those limited partner interests; and | |
• | the current market price as of the date three days before the date the notice is mailed. |
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• | obtain proof of the U.S. federal income tax status of limited partners (and their owners, to the extent relevant); and | |
• | permit us to redeem the units at their current market price held by any person whose tax status has or is reasonably likely to have a material adverse effect on our ability to operate our assets or generate revenues from our assets or who fails to comply with the procedures instituted by our general partner to obtain proof of the U.S. federal income tax status. |
• | our general partner; | |
• | any departing general partner; | |
• | any person who is or was an affiliate of a general partner or any departing general partner; | |
• | any person who is or was a director, officer, member, partner, fiduciary or trustee of any entity set forth in the preceding three bullet points; | |
• | any person who is or was serving as a director, officer, member, partner, fiduciary or trustee of another person at the request of our general partner or any departing general partner; and | |
• | any person designated by our general partner. |
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• | a current list of the name and last known address of each partner; | |
• | a copy of our tax returns; | |
• | information as to the amount of cash, and a description and statement of the agreed value of any other property or services, contributed or to be contributed by each partner and the date on which each partner became a partner; | |
• | copies of our partnership agreement, our certificate of limited partnership, related amendments and powers of attorney under which they have been executed; | |
• | information regarding the status of our business and financial condition; and | |
• | any other information regarding our affairs as is just and reasonable. |
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• | 1.0% of the total number of the securities outstanding; or | |
• | the average weekly reported trading volume of the common units for the four calendar weeks prior to the sale. |
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• | Neither we nor the operating company has elected or will elect to be treated as a corporation; | |
• | For each taxable year of our existence, more than 90% of our gross income has been and will be income that Akin Gump Strauss Hauer & Feld LLP has opined or will opine is “qualifying income” within the meaning of Section 7704(d) of the Internal Revenue Code; and | |
• | Each hedging transaction that we treat as resulting in qualifying income has been and will be appropriately identified as a hedging transaction pursuant to applicable Treasury Regulations, and has been and will be associated with oil, natural gas, or products thereof that are held or to be held by us in activities that Akin Gump Strauss Hauer & Feld LLP has opined or will opine result in qualifying income. |
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• | gross income from operations exceeds the amount required to make minimum quarterly distributions on all units, yet we only distribute the minimum quarterly distributions on all units; | |
• | we make a future offering of common units and use the proceeds of the offering in a manner that does not produce substantial additional deductions during the period described above, such as to repay indebtedness outstanding at the time of this offering or to acquire property that is not eligible for depreciation or amortization for federal income tax purposes or that is depreciable or amortizable at a rate significantly slower than the rate applicable to our assets at the time of this offering; or | |
• | legislation is passed in response to President Obama’s Budget Proposal for Fiscal Year 2012 that would limit or repeal certain U.S. federal income tax preferences currently available to oil and gas exploration and production companies. Please read “— Tax Treatment of Operations — Recent Legislative Developments.” |
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• | interest on indebtedness properly allocable to property held for investment; |
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• | our interest expense attributed to portfolio income; and | |
• | the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income. |
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• | his relative contributions to us; | |
• | the interests of all the partners in profits and losses; | |
• | the interest of all the partners in cash flow; and | |
• | the rights of all the partners to distributions of capital upon liquidation. |
• | any of our income, gain, loss or deduction with respect to those units would not be reportable by the unitholder; | |
• | any cash distributions received by the unitholder as to those units would be fully taxable; and | |
• | all of these distributions may be subject to ordinary income tax. |
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• | a short sale; | |
• | an offsetting notional principal contract; or | |
• | a futures or forward contract with respect to the partnership interest or substantially identical property. |
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• | the name, address and taxpayer identification number of the beneficial owner and the nominee; | |
• | a statement regarding whether the beneficial owner is: |
• | a person that is not a U.S. person; | |
• | a foreign government, an international organization or any wholly owned agency or instrumentality of either of the foregoing; or | |
• | a tax-exempt entity; |
• | the amount and description of units held, acquired or transferred for the beneficial owner; and | |
• | specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from sales. |
• | for which there is, or was, “substantial authority”; or | |
• | as to which there is a reasonable basis and the pertinent facts of that position are disclosed on the return. |
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• | accuracy-related penalties with a broader scope, significantly narrower exceptions, and potentially greater amounts than described above at “— Accuracy-Related Penalties”; | |
• | for those persons otherwise entitled to deduct interest on federal tax deficiencies, nondeductibility of interest on any resulting tax liability; and | |
• | in the case of a listed transaction, an extended statute of limitations. |
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• | whether the investment is prudent under Section 404(a)(1)(B) of ERISA and any other applicable Similar Laws; | |
• | whether in making the investment, the plan will satisfy the diversification requirements of Section 404(a)(1)(C) of ERISA and any other applicable Similar Laws; | |
• | whether the investment will result in recognition of unrelated business taxable income by the plan and, if so, the potential after-tax investment return. Please read “Material Tax Consequences — Tax-Exempt Organizations and Other Investors”; and | |
• | whether making such an investment will comply with the delegation of control and prohibited transaction provisions of ERISA, the Internal Revenue Code and any other applicable Similar Laws. |
• | the equity interests acquired by the employee benefit plan are publicly offered securities — i.e., the equity interests are widely held by 100 or more investors independent of the issuer and each other, are freely transferable and are registered under certain provisions of the federal securities laws; | |
• | the entity is an “operating company,” — i.e., it is primarily engaged in the production or sale of a product or service, other than the investment of capital, either directly or through a majority-owned subsidiary or subsidiaries; or |
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• | there is no significant investment by benefit plan investors, which is defined to mean that less than 25% of the value of each class of equity interest is held by the employee benefit plans referred to above that are subject to ERISA and IRAs and other similar vehicles that are subject to Section 4975 of the Internal Revenue Code. |
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Number of | ||||
Underwriter | Common Units | |||
Citigroup Global Markets Inc. | ||||
Raymond James & Associates, Inc. | ||||
Wells Fargo Securities, LLC | ||||
Barclays Capital Inc. | ||||
J.P. Morgan Securities LLC | ||||
RBC Capital Markets, LLC | ||||
Madison Williams and Company LLC | ||||
Total | ||||
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Paid by Memorial Production Partners LP | ||||||||
No Exercise | Full Exercise | |||||||
Per common unit | $ | $ | ||||||
Total | $ | $ |
• | Short sales involve secondary market sales by the underwriters of a greater number of common units than they are required to purchase in this offering. |
• | “Covered” short sales are sales of common units in an amount up to the number of common units represented by the underwriters’ option to purchase additional common units. | |
• | “Naked” short sales are sales of common units in an amount in excess of the number of common units represented by the underwriters’ option to purchase additional common units. |
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• | Covering transactions involve purchases of common units either pursuant to the underwriters’ option to purchase additional common units or in the open market after the distribution has been completed in order to cover short positions. |
• | To close a naked short position, the underwriters must purchase common units in the open market after the distribution has been completed. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the common units in the open market after pricing that could adversely affect investors who purchase in this offering. | |
• | To close a covered short position, the underwriters must purchase common units in the open market after the distribution has been completed or must exercise the underwriters’ option to purchase additional common units. In determining the source of common units to close the covered short position, the underwriters will consider, among other things, the price of common units available for purchase in the open market as compared to the price at which they may purchase common units through the underwriters’ option to purchase additional common units. |
• | Stabilizing transactions involve bids to purchase common units so long as the stabilizing bids do not exceed a specified maximum. |
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• | to any legal entity which is a qualified investor as defined in the Prospectus Directive; | |
• | to fewer than 100 or, if the Relevant Member State has implemented the relevant provision of the 2010 PD Amending Directive, 150, natural or legal persons (other than qualified investors as defined in the Prospectus Directive), as permitted under the Prospectus Directive, subject to obtaining the prior consent of the relevant Dealer or Dealers nominated by the Issuer for any such offer; or | |
• | in any other circumstances falling within Article 3(2) of the Prospectus Directive. |
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• | business strategies; | |
• | ability to replace the reserves we produce through drilling and property acquisitions; | |
• | drilling locations; | |
• | oil and natural gas reserves; | |
• | technology; | |
• | realized oil and natural gas prices; | |
• | production volumes; | |
• | lease operating expenses; | |
• | general and administrative expenses; | |
• | future operating results; | |
• | cash flows and liquidity; | |
• | availability of drilling and production equipment; | |
• | availability of oil field labor; | |
• | capital expenditures; | |
• | availability and terms of capital; | |
• | marketing of oil and natural gas; | |
• | general economic conditions; | |
• | competition in the oil and natural gas industry; | |
• | effectiveness of risk management activities; | |
• | environmental liabilities; | |
• | counterparty credit risk; | |
• | governmental regulation and taxation; | |
• | developments in oil-producing and natural-gas producing countries; and | |
• | plans, objectives, expectations and intentions. |
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228
Unaudited Pro Forma Combined Financial Statements: | ||||
F-2 | ||||
F-4 | ||||
F-5 | ||||
F-6 | ||||
F-7 | ||||
Historical Balance Sheet: | ||||
F-17 | ||||
F-18 | ||||
F-19 | ||||
Unaudited Historical Combined Financial Statements as of June 30, 2011 and December 31, 2010 and for the Six Months Ended June 30, 2011 and June 30, 2010: | ||||
F-20 | ||||
F-21 | ||||
F-22 | ||||
F-23 | ||||
F-24 | ||||
Historical Combined Financial Statements as of December 31, 2010 and 2009 and for the Years Ended December 31, 2010, 2009 and 2008: | ||||
F-42 | ||||
F-43 | ||||
F-44 | ||||
F-45 | ||||
F-46 | ||||
F-47 | ||||
FOREST ACQUISITION FINANCIAL STATEMENTS | ||||
Historical Statements of Revenues and Direct Operating Expenses for the years ended December 31, 2009 and 2008 and for the Six Months Ended June 30, 2010 (unaudited): | ||||
F-70 | ||||
F-71 | ||||
F-72 | ||||
BP ACQUISITION FINANCIAL STATEMENTS | ||||
Historical Statements of Revenues and Direct Operating Expenses for each of the three years in the period ended December 31, 2010, and the Three Months Ended March 31, 2011 and March 31, 2010 (unaudited): | ||||
F-77 | ||||
F-78 | ||||
F-79 | ||||
CARTHAGE PROPERTIES FINANCIAL STATEMENTS | ||||
Historical Statements of Revenues and Direct Operating Expenses for the years ended December 31, 2010, 2009 and 2008 and for the Three Months Ended March 31, 2011 and March 31, 2010 (unaudited): | ||||
F-83 | ||||
F-84 | ||||
F-85 |
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• | certain of the oil and natural gas properties and related assets acquired by the Predecessor from Forest Oil Corporation (“Forest Oil”) on June 30, 2010; |
• | oil and natural gas properties and related assets acquired by the Predecessor from BP America Production Company (“BP”) on May 31, 2011; and |
• | 40% of the oil and natural gas properties and related assets acquired by WHT Energy Partners LLC (“WHT”), an indirect majority-owned subsidiary of Memorial Resource, from a third party on April 8, 2011 (the “Carthage Properties”). |
F-2
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Partnership | ||||||||||||||||||||
Predecessor | Pre-offering | Offering | Pro | |||||||||||||||||
Predecessor | Retained | Partnership | Related | Forma as | ||||||||||||||||
Historical | Operations | Pro Forma | Adjustments | Adjusted | ||||||||||||||||
(a) | ||||||||||||||||||||
ASSETS | ||||||||||||||||||||
Current assets: | ||||||||||||||||||||
Cash and cash equivalents | $ | 2,377 | $ | (2,377 | ) | $ | — | $ | 130,000 | (b) | $ | — | ||||||||
250,000 | (c) | |||||||||||||||||||
(140,480 | )(d) | |||||||||||||||||||
(199,520 | )(d) | |||||||||||||||||||
Accounts receivable: | (40,000 | )(e) | ||||||||||||||||||
Oil and natural gas sales | 12,661 | (12,661 | ) | — | — | — | ||||||||||||||
Accounts receivable — affiliates | 1,388 | (1,388 | ) | — | — | |||||||||||||||
Joint interest owners and other | 2,619 | (2,619 | ) | — | — | — | ||||||||||||||
Short-term derivative instruments | 4,837 | — | 4,837 | — | 4,837 | |||||||||||||||
Prepaid expenses and other current assets | 555 | (555 | ) | — | — | — | ||||||||||||||
Total current assets | 24,437 | (19,600 | ) | 4,837 | — | 4,837 | ||||||||||||||
Property and equipment, at cost: | ||||||||||||||||||||
Oil and natural gas properties, successful efforts method | 516,129 | (19,674 | ) | 496,455 | — | 496,455 | ||||||||||||||
Other | 2,941 | (1,229 | ) | 1,712 | — | 1,712 | ||||||||||||||
Accumulated depreciation, depletion and impairment | (92,066 | ) | 9,144 | (82,922 | ) | — | (82,922 | ) | ||||||||||||
Oil and natural gas properties, net | 427,004 | (11,759 | ) | 415,245 | — | 415,245 | ||||||||||||||
Long-term derivative instruments | 4,374 | — | 4,374 | — | 4,374 | |||||||||||||||
Other long-term assets | 1,831 | (206 | ) | 1,625 | 1,600 | (e) | 1,600 | |||||||||||||
(1,625 | )(h) | |||||||||||||||||||
Total assets | $ | 457,646 | $ | (31,565 | ) | $ | 426,081 | $ | (25 | ) | $ | 426,056 | ||||||||
LIABILITIES AND PARTNERS’ CAPITAL | ||||||||||||||||||||
Current liabilities: | ||||||||||||||||||||
Accounts payable | $ | 2,476 | $ | (2,476 | ) | $ | — | $ | — | $ | — | |||||||||
Revenues payable | 4,896 | (4,896 | ) | — | — | — | ||||||||||||||
Accrued liabilities | 6,447 | (6,447 | ) | — | — | — | ||||||||||||||
Current portion of long-term debt | 85 | (6 | ) | 79 | (79 | )(d) | — | |||||||||||||
Short-term derivative instruments | 1,152 | (704 | ) | 448 | — | 448 | ||||||||||||||
Asset retirement obligations | 25 | — | 25 | — | 25 | |||||||||||||||
Total current liabilities | 15,081 | (14,529 | ) | 552 | (79 | ) | 473 | |||||||||||||
Long-term debt | 206,287 | (6,846 | ) | 199,441 | 130,000 | (b) | 130,000 | |||||||||||||
(199,441 | )(d) | |||||||||||||||||||
Deferred tax liabilities | 935 | — | 935 | — | 935 | |||||||||||||||
Asset retirement obligations | 14,213 | (810 | ) | 13,403 | — | 13,403 | ||||||||||||||
Long-term derivative instruments | 652 | (101 | ) | 551 | — | 551 | ||||||||||||||
Other long-term liabilities | 43 | (43 | ) | — | — | — | ||||||||||||||
Total liabilities | 237,211 | (22,329 | ) | 214,882 | (69,520 | ) | 145,362 | |||||||||||||
Partners’ capital | 220,435 | (9,236 | ) | 211,199 | 250,000 | (c) | 280,694 | |||||||||||||
(140,480 | )(d) | |||||||||||||||||||
(38,400 | )(e) | |||||||||||||||||||
(1,625 | )(h) | |||||||||||||||||||
Total liabilities and partners’ capital | $ | 457,646 | $ | (31,565 | ) | $ | 426,081 | $ | (25 | ) | $ | 426,056 | ||||||||
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Partnership | Predecessor | Pre-Offering | Offering | Partnership | ||||||||||||||||||||
Predecessor | Properties | Retained | Partnership | Related | Pro Forma | |||||||||||||||||||
Historical | Adjustments | Operations | Pro Forma | Adjustments | as Adjusted | |||||||||||||||||||
(f) | (a) | |||||||||||||||||||||||
Revenues: | ||||||||||||||||||||||||
Oil & natural gas sales | $ | 37,308 | $ | 52,234 | $ | (1,780 | ) | $ | 87,762 | $ | — | $ | 87,762 | |||||||||||
Other income | 1,433 | — | (29 | ) | 1,404 | — | 1,404 | |||||||||||||||||
�� | ||||||||||||||||||||||||
Total revenues | 38,741 | 52,234 | (1,809 | ) | 89,166 | — | 89,166 | |||||||||||||||||
Costs and expenses: | ||||||||||||||||||||||||
Lease operating | 13,974 | 10,280 | (1,202 | ) | 23,052 | — | 23,052 | |||||||||||||||||
Exploration | 39 | (3 | ) | 36 | — | 36 | ||||||||||||||||||
Production taxes | 2,112 | 5,432 | (157 | ) | 7,387 | — | 7,387 | |||||||||||||||||
Depreciation, depletion and amortization | 20,066 | 16,640 | (1,934 | ) | 34,772 | — | 34,772 | |||||||||||||||||
Impairment of proved oil and natural gas properties | 11,800 | — | (2,291 | ) | 9,509 | — | 9,509 | |||||||||||||||||
General and administrative | 6,116 | — | (297 | ) | 5,819 | — | 5,819 | |||||||||||||||||
Accretion | 663 | 448 | (39 | ) | 1,072 | — | 1,072 | |||||||||||||||||
Gain on derivative instruments | (10,264 | ) | — | — | (10,264 | ) | — | (10,264 | ) | |||||||||||||||
Gain on sale of properties | (1 | ) | — | 1 | — | — | — | |||||||||||||||||
Other, net | 890 | — | — | 890 | — | 890 | ||||||||||||||||||
Total costs and expenses | 45,395 | 32,800 | (5,922 | ) | 72,273 | — | 72,273 | |||||||||||||||||
Operating (loss) income | (6,654 | ) | 19,434 | 4,113 | 16,893 | — | 16,893 | |||||||||||||||||
Interest expense | (4,438 | ) | — | 294 | (4,144 | ) | (3,705 | )(g) | (4,105 | ) | ||||||||||||||
4,144 | (g) | |||||||||||||||||||||||
(400 | )(h) | |||||||||||||||||||||||
Income tax expense | (225 | ) | — | — | (225 | ) | — | (225 | ) | |||||||||||||||
Net (loss) income | $ | (11,317 | ) | $ | 19,434 | $ | 4,407 | $ | 12,524 | $ | 39 | $ | 12,563 | |||||||||||
General partner’s interest in net income | $ | |||
Limited partners’ interest in net income | $ | |||
Net income per limited partner units: | ||||
Common units (basic) | $ | |||
Subordinated units | $ | |||
Common units (diluted) | $ | |||
Weighted limited partner units outstanding: | ||||
Common units (basic) | $ | |||
Subordinated units | $ | |||
Common units (diluted) | $ |
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Partnership | ||||||||||||||||||||||||
Partnership | Predecessor | Pre-Offering | Offering | Pro | ||||||||||||||||||||
Predecessor | Properties | Retained | Partnership | Related | Forma as | |||||||||||||||||||
Historical | Adjustments | Operations | Pro Forma | Adjustments | Adjusted | |||||||||||||||||||
(f) | (a) | |||||||||||||||||||||||
Revenues: | ||||||||||||||||||||||||
Oil & natural gas sales | $ | 31,973 | $ | 12,758 | $ | (829 | ) | $ | 43,902 | $ | — | $ | 43,902 | |||||||||||
Other income | 252 | — | (8 | ) | 244 | — | 244 | |||||||||||||||||
Total revenues | 32,225 | 12,758 | (837 | ) | 44,146 | — | 44,146 | |||||||||||||||||
Costs and expenses: | ||||||||||||||||||||||||
Lease operating | 11,116 | 2,501 | (724 | ) | 12,893 | — | 12,893 | |||||||||||||||||
Exploration | 56 | — | (56 | ) | — | — | — | |||||||||||||||||
Production taxes | 2,084 | 1,507 | (66 | ) | 3,525 | — | 3,525 | |||||||||||||||||
Depreciation, depletion and amortization | 10,759 | 4,540 | (722 | ) | 14,577 | — | 14,577 | |||||||||||||||||
Impairment of proved oil and natural gas properties | 2,893 | — | (2,893 | ) | — | — | — | |||||||||||||||||
General and administrative | 3,604 | — | (125 | ) | 3,479 | — | 3,479 | |||||||||||||||||
Accretion | 466 | 91 | (23 | ) | 534 | — | 534 | |||||||||||||||||
Gain on derivative instruments | (1,987 | ) | — | — | (1,987 | ) | — | (1,987 | ) | |||||||||||||||
Gain on sale of properties | (62,729 | ) | — | 8 | (62,721 | ) | — | (62,721 | ) | |||||||||||||||
Other, net | 772 | — | — | 772 | — | 772 | ||||||||||||||||||
Total costs and expenses | (32,966 | ) | 8,639 | (4,601 | ) | (28,928 | ) | — | (28,928 | ) | ||||||||||||||
Operating (loss) income | 65,191 | 4,119 | 3,764 | 73,074 | — | 73,074 | ||||||||||||||||||
Interest expense | (3,241 | ) | — | 120 | (3,121 | ) | (1,853 | )(g) | (2,053 | ) | ||||||||||||||
3,121 | (g) | |||||||||||||||||||||||
(200 | )(h) | |||||||||||||||||||||||
Income tax expense | (122 | ) | (122 | ) | (122 | ) | ||||||||||||||||||
Net (loss) income | $ | 61,828 | $ | 4,119 | $ | 3,884 | $ | 69,831 | $ | 1,068 | $ | 70,899 | ||||||||||||
General partner’s interest in net income | $ | |||
Limited partners’ interest in net income | $ | |||
Net income per limited partner units: | ||||
Common units (basic) | $ | |||
Subordinated units | $ | |||
Common units (diluted) | $ | |||
Weighted limited partner units outstanding: | ||||
Common units (basic) | $ | |||
Subordinated units | $ | |||
Common units (diluted) | $ |
F-6
Table of Contents
Note 1 — | Basis of Presentation, the Offering, and Other Transactions |
• | The sale and contribution to the Partnership of oil and natural gas properties and related assets owned by the Predecessor, including: |
• | oil and natural gas properties and related assets acquired by the Predecessor from Forest Oil on June 30, 2010 (other than those transferred to BP on May 31, 2011); |
• | oil and natural gas properties and related assets acquired by the Predecessor from a third party on April 8, 2011; and | |
• | oil and natural gas properties and related assets acquired by the Predecessor from BP on May 31, 2011; |
• | The contribution by the Predecessor to the Partnership of certain derivative contracts, which will be used to manage exposure to oil and natural gas price volatility related to the production from the Partnership Properties; | |
• | The retention by the Predecessor of certain oil and natural gas interests and all other assets, liabilities and operations not sold or contributed to the Partnership; |
• | The issuance by the Partnership of common units and subordinated units and the payment of $ million in cash (based on the midpoint of the price range set forth on the cover page of this prospectus) as consideration for the sale and contribution of the properties noted above; and |
• | The contribution to the Partnership by the general partner of the Partnership of $ in cash and the issuance of general partner units to the general partner in respect of that contribution. |
• | The issuance and sale by the Partnership of common units to the public in the initial public offering at an assumed initial public offering price of $ per unit, resulting in gross proceeds to the Partnership of $250 million, before deduction of estimated underwriting discounts, a structuring fee and estimated offering expenses of $ million; |
• | Borrowings by the Partnership of $130 million under a new revolving credit facility; and |
F-7
Table of Contents
• | The contribution to the Partnership by the general partner of the Partnership of $ in cash and the issuance of general partner units to the general partner in respect of that contribution. |
Note 2 — | Pro Forma Adjustments and Assumptions |
F-8
Table of Contents
Forest | Carthage | BP | ||||||||||||||||||
Properties | Properties | Properties | ||||||||||||||||||
Revenues & | Revenues & | Revenues & | Additional | |||||||||||||||||
Direct | Direct | Direct | Adjustments | Partnership | ||||||||||||||||
Operating | Operating | Operating | for Property | Properties | ||||||||||||||||
Expenses | Expenses | Expenses | Acquisitions | Adjustments | ||||||||||||||||
(1) | (2) | (3) | ||||||||||||||||||
(In thousands) | ||||||||||||||||||||
Revenues: | ||||||||||||||||||||
Oil & natural gas sales | $ | 8,668 | $ | 64,738 | $ | 18,896 | $ | (37,005 | )(4) | $ | 52,234 | |||||||||
(3,063 | )(8) | |||||||||||||||||||
Other income | — | — | — | — | — | |||||||||||||||
Total revenues | 8,668 | 64,738 | 18,896 | (40,068 | ) | 52,234 | ||||||||||||||
Costs and expenses: | ||||||||||||||||||||
Lease operating | 1,975 | 9,830 | 4,373 | (5,898 | )(4) | 10,280 | ||||||||||||||
Transportation | — | 3,063 | — | (3,063 | )(8) | |||||||||||||||
Exploration | — | — | — | — | — | |||||||||||||||
Production taxes | 882 | 4,799 | 2,630 | (2,879 | )(4) | 5,432 | ||||||||||||||
Depreciation, depletion and amortization | — | — | — | 4,430 | (7) | 16,640 | ||||||||||||||
4,976 | (5) | |||||||||||||||||||
7,234 | (6) | |||||||||||||||||||
Impairment of proved oil and natural gas properties | — | — | — | — | — | |||||||||||||||
General and administrative | — | — | — | — | — | |||||||||||||||
Accretion | — | — | — | 148 | (7) | 448 | ||||||||||||||
239 | (5) | |||||||||||||||||||
61 | (6) | |||||||||||||||||||
(Gain)/loss on derivative instruments | — | — | — | — | — | |||||||||||||||
Gain on sale of properties | — | — | — | — | — | |||||||||||||||
Other, net | — | — | — | — | — | |||||||||||||||
Total costs and expenses | 2,857 | 17,692 | 7,003 | 5,248 | 32,800 | |||||||||||||||
Operating (loss) income | 5,811 | 47,046 | 11,893 | (45,316 | ) | 19,434 | ||||||||||||||
Interest expense | — | — | — | — | — | |||||||||||||||
Net (loss) income | $ | 5,811 | $ | 47,046 | $ | 11,893 | $ | (45,316 | ) | $ | 19,434 | |||||||||
F-9
Table of Contents
Carthage | BP | |||||||||||||||
Properties | Properties | Additional | ||||||||||||||
Revenues & | Revenues & | Adjustments | ||||||||||||||
Direct | Direct | for | Partnership | |||||||||||||
Operating | Operating | Property | Properties | |||||||||||||
Expenses | Expenses | Acquisitions | Adjustments | |||||||||||||
(2) | (3) | |||||||||||||||
(In thousands) | ||||||||||||||||
Revenues: | ||||||||||||||||
Oil & natural gas sales | $ | 15,069 | $ | 3,732 | $ | (8,563 | )(4) | $ | 12,758 | |||||||
(798 | )(8) | |||||||||||||||
483 | (9) | |||||||||||||||
2,835 | (10) | |||||||||||||||
Other income | — | — | — | — | ||||||||||||
Total revenues | 15,069 | 3,732 | (6,043 | ) | 12,758 | |||||||||||
Costs and expenses: | ||||||||||||||||
Lease operating | 2,124 | 993 | (1,275 | )(4) | 2,501 | |||||||||||
65 | (9) | |||||||||||||||
594 | (10) | |||||||||||||||
Transportation | 798 | — | (798 | )(8) | — | |||||||||||
Exploration | — | — | — | — | ||||||||||||
Production taxes | 1,142 | 579 | (685 | )(4) | 1,507 | |||||||||||
41 | (9) | |||||||||||||||
430 | (10) | |||||||||||||||
Depreciation, depletion and amortization | — | — | 1,361 | (5) | 4,540 | |||||||||||
3,179 | (6) | |||||||||||||||
Impairment of proved oil and natural gas properties | — | — | — | — | ||||||||||||
General and administrative | — | — | — | — | ||||||||||||
Accretion | — | — | 65 | (5) | 91 | |||||||||||
— | — | 26 | (6) | — | ||||||||||||
(Gain)/loss on derivative instruments | — | — | — | — | ||||||||||||
Gain on sale of properties | — | — | — | — | ||||||||||||
Other, net | — | — | — | — | ||||||||||||
Total costs and expenses | 4,064 | 1,572 | 3,003 | 8,639 | ||||||||||||
Operating (loss) income | 11,005 | 2,160 | (9,046 | ) | 4,119 | |||||||||||
Interest expense | — | — | — | — | ||||||||||||
Net (loss) income | $ | 11,005 | $ | 2,160 | $ | (9,046 | ) | $ | 4,119 | |||||||
(1) | Adjustments reflect the actual historical revenues and direct operating expenses of the properties acquired by BlueStone on June 30, 2010, as noted above, for the three month period ended March 31, 2011. | |
(2) | Adjustments reflect the actual historical revenues and direct operating expenses of the properties acquired by WHT on April 8, 2011, as noted above, for the three month period ended March 31, 2011. Historical lease operating statements by individual asset were used as the basis for the revenues and direct operating expenses. See footnote (9) for discussion related to the properties pro forma and actual historical results subsequent to March 31, 2011. |
F-10
Table of Contents
(3) | Adjustments reflect the actual historical revenues and direct operating expenses of the BP properties acquired by the Predecessor on May 31, 2011, as noted above, for the three month period ended March 31, 2011. Historical lease operating statements by individual asset were used as the basis for the revenues and direct operating expenses. See footnote (10) for discussion related to the properties pro forma and actual historical results subsequent to March 31, 2011. | |
(4) | Pro forma adjustments to reflect the 60% of the revenues and direct operating expenses associated with the properties acquired by WHT on April 8, 2011 that are not being sold and contributed to the Partnership in the Contribution. These adjustments are net of the reclassification described in footnote (7) below. | |
(5) | Pro forma adjustments to reflect the depletion and depreciation on property and equipment and the accretion expense on asset retirement obligations prior to the closing date of April 8, 2011 associated with the Carthage Properties. The adjustments reflect the Partnership’s 40% share of the properties acquired by WHT on April 8, 2011. | |
(6) | Pro forma adjustments to reflect the depletion and depreciation on property and equipment and the accretion expense on asset retirement obligations prior to the closing date of May 31, 2011 associated with the BP properties acquired by the Predecessor. | |
(7) | Pro forma adjustments to reflect the depletion and depreciation on property and equipment and the accretion expense on asset retirement obligations for the period January 1, 2010 through June 30, 2010 associated with the Forest Oil properties acquired by the Predecessor. On June 30, 2010, the Predecessor purchased certain oil and natural gas properties from Forest Oil for approximately $65.9 million. The actual results of the Forest Oil properties acquired are included in the Predecessor’s statement of operations for the periods subsequent to June 30, 2010. Accordingly, the pro forma combined statement of operations for the year ended December 31, 2010 is only adjusted for the revenues and operating expenses of the Forest Oil properties from January 1, 2010 to June 30, 2010. | |
(8) | Amounts represent historical transportation and marketing costs related to the Carthage Properties for the six months ended June 30, 2011 and the year ended December 31, 2010, respectively. The seller of the Carthage Properties previously recorded these amounts within expenses, as they paid such amounts on a gross basis to a third-party transportation and marketing company. However, WHT receives a wellhead price from the third-party purchasers that is net of transportation and marketing costs, and therefore, records these costs on a net basis within revenue. As a result, all transportation and marketing expenses associated with the properties acquired by WHT on April 8, 2011 have been reclassified from expenses to within revenue on the pro forma combined statements of operations to reflect the Partnership’s net presentation of such costs subsequent to the acquisition of the Carthage Properties but prior to the adjustments shown in footnote (3) above. Finally, the pro forma adjustments for the period subsequent to March 31, 2011 until the closing date of April 8, 2011 were calculated net of transportation and marketing costs. | |
(9) | Pro forma adjustments to reflect the revenues, lease operating expenses and production taxes associated with the Partnership’s 40% interest in the Carthage Properties acquired by WHT for the period subsequent to March 31, 2011 until the closing date of April 8, 2011. The properties’ actual results subsequent to the closing date of their respective acquisition are included in the Predecessor’s statement of operations. | |
(10) | Pro forma adjustments to reflect the revenues, lease operating expenses and production taxes associated with the BP properties acquired by the Predecessor for the period subsequent to March 31, 2011 until the closing date of May 31, 2011. The properties’ actual results subsequent to the closing date of their respective acquisition are included in the Predecessor’s statement of operations. |
F-11
Table of Contents
Note 3 — | Pro Forma Net Income Per Limited Partner Unit |
Note 4 — | Pro Forma Standardized Measure of Discounted Future Net Cash Flows |
F-12
Table of Contents
Year Ended December 31, 2010 | ||||||||||||||||||||||||
Proved Oil Reserves (MBbls) | ||||||||||||||||||||||||
Less: Non- | ||||||||||||||||||||||||
Predecessor | Carthage | Partnership | Pro Forma | Pro Forma | ||||||||||||||||||||
Historical | BP Properties | Properties(2) | Properties | Adjustments(2) | Partnership | |||||||||||||||||||
Proved developed and undeveloped reserves: | ||||||||||||||||||||||||
Beginning of year | 739 | 69 | 986 | 34 | — | 1,760 | ||||||||||||||||||
Extensions and discoveries | 58 | — | — | — | — | 58 | ||||||||||||||||||
Purchase of minerals in place | 259 | — | — | — | — | 259 | ||||||||||||||||||
Production | (45 | ) | (9 | ) | (51 | ) | — | (2 | ) | (107 | ) | |||||||||||||
Sale of minerals in place | — | — | — | — | — | — | ||||||||||||||||||
Revision of previous estimates | 5 | 5 | 2 | (11 | ) | 9 | 32 | |||||||||||||||||
End of year | 1,016 | 65 | 937 | 23 | 7 | 2,002 | ||||||||||||||||||
Proved developed reserves: | ||||||||||||||||||||||||
Beginning of year | 687 | 69 | 809 | 26 | — | 1,539 | ||||||||||||||||||
End of year | 904 | 65 | 760 | 18 | 7 | 1,718 | ||||||||||||||||||
Proved undeveloped reserves: | ||||||||||||||||||||||||
Beginning of year | 52 | — | 177 | 8 | — | 221 | ||||||||||||||||||
End of year | 112 | — | 177 | 5 | — | 284 |
Year Ended December 31, 2010 | ||||||||||||||||||||||||
Proved Natural Gas Reserves (MMcf) | ||||||||||||||||||||||||
Less: Non- | ||||||||||||||||||||||||
Predecessor | Carthage | Partnership | Pro Forma | Pro Forma | ||||||||||||||||||||
Historical | BP Properties | Properties(2) | Properties | Adjustments(2) | Partnership | |||||||||||||||||||
Proved developed and undeveloped reserves: | ||||||||||||||||||||||||
Beginning of year | 61,652 | 49,383 | 85,829 | 3,380 | — | 193,484 | ||||||||||||||||||
Extensions and discoveries | 7,602 | — | — | — | — | 7,602 | ||||||||||||||||||
Purchase of minerals in place | 78,046 | — | — | — | — | 78,046 | ||||||||||||||||||
Production | (7,314 | ) | (4,787 | ) | (3,436 | ) | — | (1,176 | ) | (16,713 | ) | |||||||||||||
Sale of minerals in place | — | — | — | — | — | — | ||||||||||||||||||
Revision of previous estimates | 11,190 | 2,089 | 214 | 729 | 10,493 | 23,257 | ||||||||||||||||||
End of year | 151,176 | 46,685 | 82,607 | 4,109 | 9,317 | 285,676 | ||||||||||||||||||
Proved developed reserves: | ||||||||||||||||||||||||
Beginning of year | 47,809 | 49,383 | 62,217 | 3,057 | — | 156,352 | ||||||||||||||||||
End of year | 123,529 | 46,685 | 58,925 | 2,740 | 9,317 | 235,716 | ||||||||||||||||||
Proved undeveloped reserves: | ||||||||||||||||||||||||
Beginning of year | 13,843 | — | 23,612 | 324 | — | 37,131 | ||||||||||||||||||
End of year | 27,647 | — | 23,682 | 1,369 | — | 49,960 |
F-13
Table of Contents
Year Ended December 31, 2010 | ||||||||||||||||||||||||
Proved Natural Gas Liquids Reserves (MBbls) | ||||||||||||||||||||||||
Less: Non- | ||||||||||||||||||||||||
Predecessor | Carthage | Partnership | Pro Forma | Pro Forma | ||||||||||||||||||||
Historical | BP Properties | Properties(1) | Properties | Adjustments(2) | Partnership | |||||||||||||||||||
Proved developed and undeveloped reserves: | ||||||||||||||||||||||||
Beginning of year | — | — | 4,224 | — | — | 4,224 | ||||||||||||||||||
Extensions and discoveries | 212 | — | — | — | — | 212 | ||||||||||||||||||
Purchase of minerals in place | — | — | — | — | — | — | ||||||||||||||||||
Production | (34 | ) | — | (180 | ) | — | (58 | ) | (272 | ) | ||||||||||||||
Sale of minerals in place | — | — | — | — | — | — | ||||||||||||||||||
Revision of previous estimates | 271 | — | 8 | — | 59 | 338 | ||||||||||||||||||
End of year | 449 | — | 4,052 | — | 1 | 4,502 | ||||||||||||||||||
Proved developed reserves: | ||||||||||||||||||||||||
Beginning of year | — | — | 3,060 | — | — | 3,060 | ||||||||||||||||||
End of year | 206 | — | 2,885 | — | 1 | 3,092 | ||||||||||||||||||
Proved undeveloped reserves: | ||||||||||||||||||||||||
Beginning of year | — | — | 1,164 | — | — | 1,164 | ||||||||||||||||||
End of year | 243 | — | 1,167 | — | — | 1,410 |
(1) | Reflects the Partnership’s 40% interest in the Carthage Properties acquired by WHT. | |
(2) | Consists of revisions to previous estimates of proved reserves related primarily to oil and gas properties acquired by the Predecessor from BP in 2011 and production related to the Forest Properties acquired by the Predecessor on June 30, 2010. |
Year Ended December 31, 2010 | ||||||||||||||||
NGL | Equivalent | |||||||||||||||
Oil (MBbls) | Gas (MMcf) | (MBbls) | (Mmcfe) | |||||||||||||
Proved developed and undeveloped reserves: | ||||||||||||||||
Beginning of year | 1,760 | 193,484 | 4,224 | 229,387 | ||||||||||||
Extensions and discoveries | 58 | 7,602 | 212 | 9,229 | ||||||||||||
Purchase of minerals in place | 259 | 78,046 | — | 79,600 | ||||||||||||
Production | (107 | ) | (16,713 | ) | (272 | ) | (18,985 | ) | ||||||||
Sale of minerals in place | — | — | — | — | ||||||||||||
Revision of previous estimates | 32 | 23,257 | 338 | 25,466 | ||||||||||||
End of year | 2,002 | 285,676 | 4,502 | 324,697 | ||||||||||||
Proved developed reserves: | ||||||||||||||||
Beginning of year | 1,539 | 156,352 | 3,060 | 183,946 | ||||||||||||
End of year | 1,718 | 235,716 | 3,092 | 264,572 | ||||||||||||
Proved undeveloped reserves: | ||||||||||||||||
Beginning of year | 221 | 37,131 | 1,164 | 45,441 | ||||||||||||
End of year | 284 | 49,960 | 1,410 | 60,125 |
F-14
Table of Contents
• | future costs and selling prices will probably differ from those required to be used in these calculations; | |
• | due to future market conditions and governmental regulations, actual rates of production in future years may vary significantly from the rate of production assumed in the calculations; | |
• | a 10% discount rate may not be reasonable as a measure of the relative risk inherent in realizing future net oil and natural revenues; and | |
• | the effects of federal income taxes have been excluded. |
F-15
Table of Contents
Non- | ||||||||||||||||||||
Predecessor | Contribution | Partnership | Pro Forma | Pro Forma | ||||||||||||||||
Historical | Adjustments | Properties | Adjustments (1) | Partnership | ||||||||||||||||
Future cash inflows | $ | 780,477 | $ | 750,264 | $ | 18,491 | $ | 41,345 | $ | 1,553,595 | ||||||||||
Future production costs | (291,486 | ) | (250,185 | ) | (8,808 | ) | (32,628 | ) | (565,491 | ) | ||||||||||
Future development costs | (68,046 | ) | (40,321 | ) | (3,686 | ) | — | (104,681 | ) | |||||||||||
Future income tax expense(2) | (5,463 | ) | (5,252 | ) | (129 | ) | (289 | ) | (10,875 | ) | ||||||||||
Future net cash flows before 10% discount | 415,482 | 454,506 | 5,868 | 8,428 | 872,548 | |||||||||||||||
10% annual discount for estimated timing of cash flows | (231,667 | ) | (276,336 | ) | (2,540 | ) | (7,887 | ) | (513,350 | ) | ||||||||||
Standardized measure of discounted future net cash flows | $ | 183,815 | $ | 178,170 | $ | 3,328 | $ | 541 | $ | 359,198 | ||||||||||
(1) | Consists of revisions to previous estimates of proved reserves related primarily to oil and gas properties acquired by the Predecessor from BP in 2011. | |
(2) | Represents future amounts owed associated with Texas margin tax. |
December 31, 2010 | ||||
(In thousands) | ||||
Beginning of year | $ | 215,970 | ||
Sale of oil and natural gas produced, net of production costs | (52,623 | ) | ||
Purchase of minerals in place | 104,729 | |||
Sales of minerals in place | — | |||
Extensions and discoveries | 8,526 | |||
Changes in income taxes, net | (1,747 | ) | ||
Changes in prices and costs | 57,481 | |||
Previously estimated development costs incurred | 2,229 | |||
Net changes in future development costs | (4,948 | ) | ||
Revisions of previous quantities | 15,646 | |||
Accretion of discount | 21,584 | |||
Changes in production rates and other | (7,649 | ) | ||
End of year | $ | 359,198 | ||
F-16
Table of Contents
F-17
Table of Contents
April 27, 2011 | June 30, 2011 | |||||||
(Unaudited) | ||||||||
Assets | ||||||||
Cash | — | — | ||||||
Total assets | $ | — | $ | — | ||||
Partners’ capital | ||||||||
Limited partners’ capital | 999 | 999 | ||||||
General partners’ capital | 1 | 1 | ||||||
Receivable from partners | (1,000 | ) | (1,000 | ) | ||||
Total partners’ capital | $ | — | $ | — | ||||
F-18
Table of Contents
Note 1 — | Organization |
F-19
Table of Contents
Pro forma | ||||||||||||
June 30, 2011 | June 30, 2011 | December 31, 2010 | ||||||||||
(unaudited) | (unaudited) | |||||||||||
(In thousands) | ||||||||||||
ASSETS | ||||||||||||
Current assets: | ||||||||||||
Cash and cash equivalents | $ | 2,377 | $ | 2,377 | $ | 5,654 | ||||||
Accounts receivable: | ||||||||||||
Oil and natural gas sales | 12,661 | 12,661 | 6,175 | |||||||||
Amounts receivable-affiliates | 1,388 | 1,388 | — | |||||||||
Joint interest owners and other | 2,619 | 2,619 | 3,848 | |||||||||
Short-term derivative instruments | 4,837 | 4,837 | 3,791 | |||||||||
Prepaid expenses and other current assets | 555 | 555 | 771 | |||||||||
Total current assets | 24,437 | 24,437 | 20,239 | |||||||||
Property and equipment, at cost: | ||||||||||||
Oil and natural gas properties, successful efforts method | 516,129 | 516,129 | 314,975 | |||||||||
Other | 2,941 | 2,941 | 2,553 | |||||||||
519,070 | 519,070 | 317,528 | ||||||||||
Accumulated depreciation, depletion and impairment | (92,066 | ) | (92,066 | ) | (93,224 | ) | ||||||
Oil and natural gas properties, net | 427,004 | 427,004 | 224,304 | |||||||||
Long-term derivative instruments | 4,374 | 4,374 | 2,699 | |||||||||
Other long-term assets | 1,831 | 1,831 | 1,298 | |||||||||
Total assets | $ | 457,646 | $ | 457,646 | $ | 248,540 | ||||||
LIABILITIES AND PARTNERS’ CAPITAL | ||||||||||||
Current liabilities: | ||||||||||||
Accounts payable | $ | 2,476 | $ | 2,476 | $ | 8,482 | ||||||
Revenues payable | 4,896 | 4,896 | 3,564 | |||||||||
Accrued liabilities | 6,447 | 6,447 | 3,874 | |||||||||
Distribution payable | 140,480 | |||||||||||
Current portion of long-term debt | 85 | 85 | 69 | |||||||||
Short-term derivative instruments | 1,152 | 1,152 | 109 | |||||||||
Asset retirement obligations | 25 | 25 | 25 | |||||||||
Total current liabilities | 15,081 | 155,561 | 16,123 | |||||||||
Long-term debt | 206,287 | 206,287 | 115,359 | |||||||||
Deferred tax liabilities | 935 | 935 | 225 | |||||||||
Asset retirement obligations | 14,213 | 14,213 | 10,867 | |||||||||
Long-term derivative instruments | 652 | 652 | 109 | |||||||||
Other long-term liabilities | 43 | 43 | 56 | |||||||||
Total liabilities | 237,211 | 377,691 | 142,739 | |||||||||
Commitments and contingencies (Note 10) | ||||||||||||
Partners’ capital | 220,435 | 79,955 | 105,801 | |||||||||
Total liabilities and partners’ capital | $ | 457,646 | $ | 457,646 | $ | 248,540 | ||||||
F-20
Table of Contents
2011 | 2010 | |||||||
(Unaudited) | ||||||||
(In thousands) | ||||||||
Revenues: | ||||||||
Oil & natural gas sales | $ | 31,973 | $ | 14,813 | ||||
Other income | 252 | 1,314 | ||||||
Total revenues | 32,225 | 16,127 | ||||||
Costs and expenses: | ||||||||
Lease operating | 11,116 | 5,205 | ||||||
Exploration | 56 | — | ||||||
Production taxes | 2,084 | 967 | ||||||
Depreciation, depletion and amortization | 10,759 | 8,173 | ||||||
Impairment of proved oil and natural gas properties | 2,893 | 3,319 | ||||||
General and administrative | 3,604 | 2,271 | ||||||
Accretion | 466 | 251 | ||||||
(Gain)/loss on derivative instruments | (1,987) | (6,254) | ||||||
Gain on sale of properties | (62,729) | — | ||||||
Other, net | 772 | 891 | ||||||
Total costs and expenses | (32,966) | 14,823 | ||||||
Operating (loss) income | 65,191 | 1,304 | ||||||
Interest expense | (3,241) | (1,828) | ||||||
Net (loss) income before income taxes | $ | 61,950 | $ | (524) | ||||
Income tax expense | (122) | — | ||||||
Net income (loss) | $ | 61,828 | $ | (524) | ||||
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Total Partners’ | ||||
Capital | ||||
(Unaudited) | ||||
(In thousands) | ||||
Balance December 31, 2010 | $ | 105,801 | ||
Contributions from partners | 52,806 | |||
Distributions to partners | — | |||
Net income | 61,828 | |||
Balance June 30, 2011 | $ | 220,435 | ||
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2011 | 2010 | |||||||
(Unaudited) | ||||||||
(In thousands) | ||||||||
Cash flows from operating activities: | ||||||||
Net (loss) income | $ | 61,828 | $ | (524) | ||||
Adjustments to reconcile net (loss) income to net cash provided by operating activities: | ||||||||
Depreciation, depletion, and amortization | 10,759 | 8,173 | ||||||
Impairment of proved oil and natural gas properties | 2,893 | 3,319 | ||||||
Unrealized (gain) loss on derivatives | 703 | (2,915) | ||||||
Deferred income tax expense | 122 | — | ||||||
Amortization of loan origination fees | 214 | 409 | ||||||
Accretion | 466 | 251 | ||||||
Gain on sale of properties | (62,729) | — | ||||||
Exploratory dry hole costs | 56 | — | ||||||
Premiums paid for derivatives | (2,847) | — | ||||||
Premiums received for derivatives | 1,008 | — | ||||||
Changes in operating assets and liabilities, net of effects of acquisitions: | ||||||||
Accounts receivable | (6,644) | 1,727 | ||||||
Prepaid expenses and other assets | 370 | 369 | ||||||
Accounts payable | (1,636) | 2,740 | ||||||
Revenue payable | 842 | (1,421) | ||||||
Accrued liabilities | 2,372 | 3,466 | ||||||
Other | 559 | (131) | ||||||
Net cash provided by operating activities | $ | 8,336 | $ | 15,463 | ||||
Cash flows from investing activities: | ||||||||
Acquisition of oil and natural gas properties | (137,929) | (98,014) | ||||||
Additions to oil and gas properties | (16,160) | (3,455) | ||||||
Additions to other property and equipment | (385) | (204) | ||||||
Proceeds from the sale of oil and gas properties | 13 | 1,400 | ||||||
Net cash used by investing activities | $ | (154,461) | $ | (100,273) | ||||
Cash flows from financing activities: | ||||||||
Advances on revolving credit facility | 91,946 | 67,565 | ||||||
Payments on revolving credit facility | (1,003) | — | ||||||
Contributed capital | 52,806 | 19,751 | ||||||
Loan origination fees | (901) | (1,330) | ||||||
Net cash provided by financing activities | 142,848 | 85,986 | ||||||
Net increase (decrease) in cash | $ | (3,277) | $ | 1,176 | ||||
Cash and cash equivalents, beginning of period | $ | 5,654 | $ | 5,297 | ||||
Cash and cash equivalents, end of period | $ | 2,377 | $ | 6,473 | ||||
Supplemental disclosure of cash flows: | ||||||||
Cash paid for interest | $ | 2,042 | $ | 1,224 | ||||
Noncash investing and financing activities: | ||||||||
Fair value of assets acquired in excess of cash paid and net book of properties transferred | 69,645 | — | ||||||
Assumptions of asset retirement obligations related to properties acquired | 2,661 | 5,868 |
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Table of Contents
Note 1 — | Organization |
• | BlueStone Natural Resources, LLC is a Delaware limited liability company formed in January 2006 to engage in the acquisition, development, production and exploration and sale of oil and natural gas. BlueStone is a wholly-owned subsidiary of BlueStone Natural Resources Holdings, LLC (“Holdings”), whose sole purpose is to provide financing for BlueStone. BlueStone owns oil and natural gas producing properties in Texas. Prior to the Offering, Memorial Resource owned an 89.45% interest in BlueStone and certain members of BlueStone’s management owned a 10.55% interest. |
• | Certain carved-out oil and natural gas properties (“Classic Carve-Out”) of Classic Hydrocarbons Holdings, L.P., (“Classic”) that will be acquired by the Partnership at the closing of the initial public offering. Classic was formed in 2006 to engage in the exploration, development, production, and sale of oil and natural gas primarily in East Texas. Prior to the Offering, Memorial Resource owned a 90.21% limited partner interest in Classic and an 83.33% membership interest in the general partner of Classic. | |
• | The Partnership will acquire at the closing of the initial public offering a 40% undivided interest in oil and natural gas properties (“WHT Assets”) owned by WHT Energy Partners LLC (“WHT”). The WHT Assets were acquired on April 8, 2011, therefore, the results of operations (proportionally consolidated) have been included in the Predecessor from that date forward. Prior to April 8, 2011, WHT did not have any oil and natural gas assets. |
Note 2 — | Basis of Presentation and Significant Accounting Policies |
(a) | Basis of Presentation |
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(b) | Use of Estimates |
(c) | Principles of Consolidation |
(d) | Cash and Cash Equivalents |
(e) | Concentrations of Credit Risk |
F-25
Table of Contents
(f) | Oil and Natural Gas Properties |
(g) | Oil and Gas Reserves |
F-26
Table of Contents
(h) | Other Property and Equipment |
(i) | Impairments |
F-27
Table of Contents
(j) | Asset Retirement Obligations |
Asset retirement obligations at December 31, 2010 | $ | 10,892 | ||
Liabilities added from acquisition or drilling | 2,957 | |||
Liabilities removed upon sale of wells | (64) | |||
Accretion expense | 466 | |||
Revision of estimates | (13) | |||
Asset retirement obligations at June 30, 2011 | $ | 14,238 | ||
(k) | Other Long-Term Assets |
(l) | Revenue Recognition |
(m) | General and Administrative Expense |
(n) | Derivative Instruments |
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Table of Contents
(o) | Income Taxes |
(p) | Equity Compensation |
(q) | New Accounting Pronouncements |
F-29
Table of Contents
Note 3 — | Acquisitions and Divestitures |
Consideration paid for Carthage Properties: | ||||
Cash | $ | 121,166 | ||
Liabilities assumed | 490 | |||
Total consideration | $ | 121,656 | ||
Recognized amounts of identifiable assets acquired and liabilities assumed: | ||||
Oil and gas properties | 123,592 | |||
Vehicles | 15 | |||
Suspense liabilities assumed | (490 | ) | ||
Asset retirement obligations | (1,461 | ) | ||
Total identifiable net assets | $ | 121,656 | ||
Six Months Ended June 30, 2011 | Six Months Ended June 30, 2010 | |||||||||||||||
Actual | Pro Forma | Actual | Pro Forma | |||||||||||||
(In thousands) | (In thousands) | |||||||||||||||
BP and Carthage Properties: | ||||||||||||||||
Revenues | $ | 32,225 | $ | 45,408 | $ | 16,127 | $ | 40,811 | ||||||||
Net (loss) income | $ | 61,828 | $ | 66,119 | $ | (524 | ) | $ | 11,126 |
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Oil and gas properties | $ | 15,397 | ||
Prepaid assets | 450 | |||
Assumed liabilities | (1,728) | |||
Net purchase price | $ | 14,119 | ||
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Note 4 — | Fair Value Measurements of Financial Instruments |
Fair Value Measurements at June 30, 2011 Using | ||||||||||||||||
Significant | ||||||||||||||||
Quoted Prices in | Significant Other | Unobservable | ||||||||||||||
Active Markets | Observable Inputs | Inputs | Fair Value at | |||||||||||||
(Level 1) | (Level 2) | (Level 3) | June 30, 2011 | |||||||||||||
Assets: | ||||||||||||||||
Commodity derivative price swap contracts | $ | — | $ | 2,984 | $ | — | $ | 2,984 | ||||||||
Commodity derivative price collar contracts | 6,232 | 6,232 | ||||||||||||||
Commodity derivative price put options | — | 1,108 | — | 1,108 | ||||||||||||
Total assets | $ | — | $ | 10,324 | $ | — | $ | 10,324 | ||||||||
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Fair Value Measurements at June 30, 2011 Using | ||||||||||||||||
Significant | ||||||||||||||||
Quoted Prices in | Significant Other | Unobservable | ||||||||||||||
Active Markets | Observable Inputs | Inputs | Fair Value at | |||||||||||||
(Level 1) | (Level 2) | (Level 3) | June 30, 2011 | |||||||||||||
Liabilities: | ||||||||||||||||
Commodity derivative price swap contracts | $ | — | $ | (204) | $ | — | $ | (204) | ||||||||
Commodity derivative price collar contracts | — | (548) | — | (548) | ||||||||||||
Commodity derivative put options | — | (1,360) | — | (1,360) | ||||||||||||
Interest rate swaps | — | (805) | — | (805) | ||||||||||||
Total liabilities | $ | — | $ | (2,917) | $ | — | $ | (2,917) | ||||||||
Fair Value Measurements at December 31, 2010 Using | ||||||||||||||||
Significant | ||||||||||||||||
Quoted Prices in | Significant Other | Unobservable | Fair Value at | |||||||||||||
Active Markets | Observable Inputs | Inputs | December 31, | |||||||||||||
(Level 1) | (Level 2) | (Level 3) | 2010 | |||||||||||||
Assets: | ||||||||||||||||
Commodity derivative price swap contracts | $ | — | $ | 3,067 | $ | — | $ | 3,067 | ||||||||
Commodity derivative price collar contracts | — | 4,086 | — | 4,086 | ||||||||||||
Total assets | $ | — | $ | 7,153 | $ | — | $ | 7,153 | ||||||||
Liabilities: | ||||||||||||||||
Commodity derivative price collar contracts | $ | — | $ | (420) | $ | — | $ | (420) | ||||||||
Commodity derivative put options | — | (58) | — | (58) | ||||||||||||
Commodity derivative interest rate swaps | — | (403) | — | (403) | ||||||||||||
Total liabilities | $ | — | $ | (881) | $ | — | $ | (881) | ||||||||
Note 5 — | Risk Management and Derivative Instruments |
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Table of Contents
(a) | Commodity Derivatives |
Natural Gas Swaps | ||||||||||||||
Average Monthly | Weighted Average | |||||||||||||
Period Covering: | Volumes (MMBtu) | Fixed Price | ||||||||||||
7/1/2011 | 12/31/2011 | 186,000 | $ | 5.41 | ||||||||||
1/1/2012 | 12/31/2012 | 188,000 | $ | 5.32 | ||||||||||
1/1/2013 | 12/31/2013 | 150,000 | $ | 5.24 |
Natural Gas Collars | ||||||||||||||||||
Average Monthly | Weighted Average | Weighted Average | ||||||||||||||||
Period Covering: | Volumes (MMBtu) | Floor Price | Ceiling Price | |||||||||||||||
7/1/2011 | 12/31/2011 | 535,000 | $ | 4.90 | $ | 6.05 | ||||||||||||
1/1/2012 | 12/31/2012 | 619,500 | $ | 4.79 | $ | 5.91 | ||||||||||||
1/1/2013 | 12/31/2013 | 607,00 | $ | 4.74 | $ | 5.82 | ||||||||||||
1/1/2014 | 12/31/2014 | 120,000 | $ | 5.08 | $ | 6.31 | ||||||||||||
1/1/2015 | 12/31/2015 | 80,000 | $ | 5.25 | $ | 6.75 |
Natural Gas Put Options | ||||||||||||||
Average Monthly | ||||||||||||||
Period Covering: | Volumes (MMBtu) | Strike Price | ||||||||||||
7/1/2011 | 12/31/2011 | 254,000 | $ | 4.30 | ||||||||||
1/1/2012 | 12/31/2012 | 70,000 | $ | 4.80 |
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Table of Contents
Oil Collars | ||||||||||||||||||
Average Monthly | Weighted Average | Weighted Average | ||||||||||||||||
Period Covering: | Volumes (Bbls) | Floor Price | Ceiling Price | |||||||||||||||
1/1/2011 | 12/31/2011 | 4,800 | $ | 86.25 | $ | 113.62 | ||||||||||||
1/1/2012 | 12/31/2012 | 4,500 | $ | 86.67 | $ | 115.12 | ||||||||||||
1/1/2013 | 12/31/2013 | 4,750 | $ | 87.16 | $ | 116.94 | ||||||||||||
1/1/2014 | 12/31/2014 | 3,200 | $ | 90.00 | $ | 117.72 |
Oil Put Options | ||||||||||||||
Average Monthly | ||||||||||||||
Period Covering: | Volumes (Bbls) | Strike Price | ||||||||||||
7/1/2011 | 12/31/2011 | 600 | $ | 85.00 |
Natural Gas Liquids | ||||||||||||||||||||
Average Monthly | Weighted Average | Weighted Average | ||||||||||||||||||
Beginning Month | Ending Month | Product | Volumes (MMBtu) | Floor Price | Ceiling Price | |||||||||||||||
7/1/2011 | 12/31/2012 | Propane | 1,200 | $ | 52.50 | $ | 66.78 | |||||||||||||
7/1/2011 | 12/31/2012 | Normal Butane | 600 | $ | 71.40 | $ | 86.10 | |||||||||||||
7/1/2011 | 12/31/2012 | Iso-Butane | 400 | $ | 71.40 | $ | 89.04 | |||||||||||||
7/1/2011 | 12/31/2012 | Pentane | 1,600 | $ | 94.50 | $ | 117.60 |
(b) | Interest Rate Swaps |
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(c) | Balance Sheet Presentation |
June 30, | December 31, | |||||||||
Type | Balance Sheet Location(1) | 2011 | 2010 | |||||||
Natural Gas Contracts | Short-term derivative instruments — Current assets | $ | 5,351 | $ | 4,120 | |||||
Oil Contracts | Short-term derivative instruments — Current assets | 111 | — | |||||||
NGL Contracts | Short-term derivative instruments — Current assets | 2 | — | |||||||
Natural Gas Contracts | Long-term derivative instruments — Long-term assets | 4,615 | 3,033 | |||||||
Oil Contracts | Long-term derivative instruments — Long-term assets | 241 | — | |||||||
NGL Contracts | Long-term derivative instruments — Long-term assets | 2 | — | |||||||
Natural Gas Contracts | Short-term derivative instruments — Current liabilities | (1,021) | (79) | |||||||
Oil Contracts | Short-term derivative instruments — Current liabilities | (54) | (81) | |||||||
Interest Rate Swaps | Short-term derivative instruments — Current liabilities | (704) | (153) | |||||||
Natural Gas Contracts | Long-term derivative instruments — Long-term liabilities | (840) | (209) | |||||||
Oil Contracts | Long-term derivative instruments — Long-term liabilities | (195) | (109) | |||||||
Interest Rate Swaps | Long-term derivative instruments — Long-term liabilities | (101) | (250) | |||||||
Net derivative financial instruments | $ | 7,407 | $ | 6,272 | ||||||
(1) | The fair value of derivative instruments reported in the Predecessor’s combined balance sheets are subject to netting arrangements and qualify for net presentation. The following table reports the net derivative fair values as reported in the Predecessor’s combined balance sheets at June 30, 2011 and December 31, 2010: |
June 30, 2011 | December 31, 2010 | |||||||
Combined balance sheet classification: | ||||||||
Current derivative contracts: | ||||||||
Assets | $ | 4,837 | $ | 3,791 | ||||
Liabilities | (1,152) | (109) | ||||||
Net current | $ | 3,685 | $ | 3,682 | ||||
Noncurrent derivative contracts: | ||||||||
Assets | $ | 4,374 | $ | 2,699 | ||||
Liabilities | (652) | (109) | ||||||
Net noncurrent | $ | 3,722 | $ | 2,590 | ||||
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Table of Contents
(d) | Gains (Losses) on Derivatives |
Statements of | ||||||||||
Operations | Six Months Ended | |||||||||
Location | June 30, 2011 | June 30, 2010 | ||||||||
Gain/(loss)on | ||||||||||
Commodity derivative contracts(1) | derivatives | 1,987 | 6,254 | |||||||
Interest rate swaps(2) | Interest expense | (636) | (24) |
(1) | Included in these amounts are net cash receipts of approximately $2,245 and $3,366 for the six months ended June 30, 2011 and June 30, 2010, respectively. | |
(2) | Included in the amounts are net cash payments of approximately $192 and $56 for the six months ended June 30, 2011 and June 30, 2010, respectively. |
Note 6 — | Long Term Debt |
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Note 7 — | Partners’ Capital |
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Table of Contents
Note 8 — | Incentive Interests |
F-39
Table of Contents
Note 9 — | Related Party and Affiliate Transactions |
Note 10 — | Commitments and Contingencies |
(a) | Lease Agreements |
F-40
Table of Contents
(b) | Litigation |
(c) | Noncompete Agreements |
Note 11 — | Defined Contribution Plan |
Note 12 — | Pro Forma Information |
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Table of Contents
F-42
Table of Contents
2010 | 2009 | |||||||
(In thousands) | ||||||||
ASSETS | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 5,654 | $ | 5,297 | ||||
Accounts receivable: | ||||||||
Oil and natural gas sales | 6,175 | 5,025 | ||||||
Joint interest owners and other | 3,848 | 2,362 | ||||||
Short-term derivative instruments | 3,791 | 3,086 | ||||||
Prepaid expenses and other current assets | 771 | 1,110 | ||||||
Total current assets | 20,239 | 16,880 | ||||||
Property and equipment, at cost: | ||||||||
Oil and natural gas properties, successful efforts method | 314,975 | 187,217 | ||||||
Other | 2,553 | 2,137 | ||||||
317,528 | 189,354 | |||||||
Accumulated depreciation, depletion and impairment | (93,224) | (61,358) | ||||||
Oil and natural gas properties, net | 224,304 | 127,996 | ||||||
Long-term derivative instruments | 2,699 | 814 | ||||||
Other long-term assets | 1,298 | 463 | ||||||
Total assets | $ | 248,540 | $ | 146,153 | ||||
LIABILITIES AND PARTNERS’ CAPITAL | ||||||||
Current liabilities: | ||||||||
Accounts payable | $ | 8,482 | $ | 3,442 | ||||
Revenues payable | 3,564 | 3,140 | ||||||
Accrued liabilities | 3,874 | 654 | ||||||
Current portion of long-term debt | 69 | 24 | ||||||
Short-term derivative instruments | 109 | 13 | ||||||
Asset retirement obligations | 25 | 113 | ||||||
Total current liabilities | 16,123 | 7,386 | ||||||
Long-term debt | 115,359 | 61,760 | ||||||
Deferred tax liabilities | 225 | — | ||||||
Asset retirement obligations | 10,867 | 3,693 | ||||||
Long-term derivative instruments | 109 | 288 | ||||||
Other long-term liabilities | 56 | 38 | ||||||
Total liabilities | 142,739 | 73,165 | ||||||
Commitments and contingencies (Note 11) | ||||||||
Partners’ capital | 105,801 | 72,988 | ||||||
Total liabilities and partners’ capital | $ | 248,540 | $ | 146,153 | ||||
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2010 | 2009 | 2008 | ||||||||||
(In thousands) | ||||||||||||
Revenues: | ||||||||||||
Oil & natural gas sales | $ | 37,308 | $ | 24,541 | $ | 49,313 | ||||||
Other income | 1,433 | 319 | 622 | |||||||||
Total revenues | 38,741 | 24,860 | 49,935 | |||||||||
Costs and expenses: | ||||||||||||
Lease operating | 13,974 | 11,207 | 8,843 | |||||||||
Exploration | 39 | 2,690 | 374 | |||||||||
Production taxes | 2,112 | 1,464 | 3,127 | |||||||||
Depreciation, depletion and amortization | 20,066 | 15,226 | 12,353 | |||||||||
Impairment of proved oil and natural gas properties | 11,800 | 3,480 | 14,166 | |||||||||
General and administrative | 6,116 | 4,811 | 3,835 | |||||||||
Accretion | 663 | 320 | 224 | |||||||||
Gain on derivative instruments | (10,264) | (10,834) | (9,815) | |||||||||
Gain on sale of properties | (1) | (7,851) | (7,395) | |||||||||
Other, net | 890 | 304 | — | |||||||||
Total costs and expenses | 45,395 | 20,817 | 25,712 | |||||||||
Operating (loss) income | (6,654) | 4,043 | 24,223 | |||||||||
Interest expense | (4,438) | (2,937) | (3,138) | |||||||||
Income (loss) before income taxes | (11,092) | 1,106 | 21,085 | |||||||||
Income tax expense | (225) | — | — | |||||||||
Net (loss) income | $ | (11,317) | $ | 1,106 | $ | 21,085 | ||||||
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Total Partners’ | ||||
Capital | ||||
(In thousands) | ||||
Balance January 1, 2008 | $ | 37,682 | ||
Contributions from partners | — | |||
Distributions to partners | (4,191) | |||
Net income | 21,085 | |||
Balance December 31, 2008 | 54,576 | |||
Contributions from partners | 17,306 | |||
Distributions to partners | — | |||
Net income | 1,106 | |||
Balance December 31, 2009 | 72,988 | |||
Contributions from partners | 44,130 | |||
Distributions to partners | — | |||
Net loss | (11,317) | |||
Balance December 31, 2010 | $ | 105,801 | ||
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2010 | 2009 | 2008 | ||||||||||
(In thousands) | ||||||||||||
Cash flows from operating activities: | ||||||||||||
Net (loss) income | $ | (11,317 | ) | $ | 1,106 | $ | 21,085 | |||||
Adjustments to reconcile net (loss) income to net cash provided | ||||||||||||
by operating activities: | ||||||||||||
Depreciation, depletion, and amortization | 20,066 | 15,226 | 12,353 | |||||||||
Impairment of proved oil and natural gas properties | 11,800 | 3,480 | 14,166 | |||||||||
Unrealized (gain) loss on derivatives | (2,674 | ) | 6,430 | (9,975 | ) | |||||||
Deferred income tax expense | 225 | — | — | |||||||||
Amortization of loan origination fees | 745 | 109 | 26 | |||||||||
Accretion | 663 | 320 | 224 | |||||||||
Gain on sale of properties | (1 | ) | (7,851 | ) | (7,395 | ) | ||||||
Exploratory dry hole costs | 39 | 2,690 | 374 | |||||||||
Changes in operating assets and liabilities: | ||||||||||||
Accounts receivable | (2,637 | ) | 6,522 | (5,044 | ) | |||||||
Prepaid expenses and other assets | 227 | (729 | ) | (187 | ) | |||||||
Accounts payable | 855 | (12,597 | ) | 8,546 | ||||||||
Revenue payable | 423 | (1,171 | ) | (494 | ) | |||||||
Accrued liabilities | 1,771 | (842 | ) | (969 | ) | |||||||
Other | 103 | (21 | ) | 128 | ||||||||
Net cash provided by operating activities | 20,288 | 12,672 | 32,838 | |||||||||
Cash flows from investing activities: | ||||||||||||
Acquisition of oil and natural gas properties | (104,542 | ) | (17,455 | ) | (15,199 | ) | ||||||
Additions to oil and gas properties | (13,129 | ) | (19,034 | ) | (45,378 | ) | ||||||
Additions to other property and equipment | (416 | ) | (210 | ) | (388 | ) | ||||||
Proceeds from the sale of oil and gas properties | 1,400 | 11,752 | 15,418 | |||||||||
Net cash used by investing activities | (116,687 | ) | (24,947 | ) | (45,547 | ) | ||||||
Cash flows from financing activities: | ||||||||||||
Advances on revolving credit facility | 115,106 | 11,948 | 24,570 | |||||||||
Payments on revolving credit facility | (61,600 | ) | (12,749 | ) | (8,750 | ) | ||||||
Contributed capital | 44,130 | 17,306 | — | |||||||||
Distribution to partners | — | — | (4,191 | ) | ||||||||
Proceeds from borrowings of long-term debt | 182 | — | — | |||||||||
Repayment of borrowings of long-term debt | (44 | ) | (27 | ) | (10 | ) | ||||||
Loan origination fees | (1,018 | ) | (489 | ) | — | |||||||
Net cash provided by financing activities | $ | 96,756 | $ | 15,989 | $ | 11,619 | ||||||
Net increase (decrease) in cash | 357 | 3,714 | (1,090 | ) | ||||||||
Cash and cash equivalents, beginning of year | $ | 5,297 | $ | 1,583 | $ | 2,673 | ||||||
Cash and cash equivalents, end of year | $ | 5,654 | $ | 5,297 | $ | 1,583 | ||||||
Supplemental cash flows: | ||||||||||||
Cash paid for interest | $ | 4,309 | $ | 2,677 | $ | 2,087 | ||||||
Noncash investing and financing activities: | ||||||||||||
Purchase of fixed assets with note payable | — | 117 | — | |||||||||
Environmental remediation net liability recorded as part of Merit acquisition (see Note 3) | 1,450 | — | — |
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Table of Contents
Note 1 — | Organization |
• | BlueStone Natural Resources, LLC (“BlueStone”) is a Delaware limited liability company formed in January 2006 to engage in the acquisition, development, production and exploration and sale of oil and natural gas. BlueStone is a wholly owned subsidiary of BlueStone Natural Resources Holdings, LLC (“Holdings”), whose sole purpose is to provide financing for BlueStone. BlueStone owns oil and natural gas producing properties in Texas. Prior to the Offering, Memorial Resource owned an 89.45% interest in BlueStone and certain members of BlueStone’s management owned a 10.55% interest. | |
• | Certain carved-out oil and natural gas properties (“Classic Carve-Out”) of Classic Hydrocarbons Holdings, L.P. (“Classic”) that will be acquired by the Partnership at the closing of the initial public offering. Classic was formed in 2006 to engage in the exploration, development, production, and sale of oil and natural gas primarily in East Texas. Prior to the Offering, Memorial Resource owned a 90.21% limited partner interest in Classic and an 83.33% membership interest in the general partner of Classic. |
Note 2 — | Basis of Presentation and Significant Accounting Policies |
(a) | Basis of Presentation |
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Table of Contents
(b) | Use of Estimates |
(c) | Principles of Combination |
(d) | Cash and Cash Equivalents |
(e) | Concentrations of Credit Risk and Significant Customers |
F-48
Table of Contents
(f) | Oil and Natural Gas Properties |
F-49
Table of Contents
2010 | 2009 | 2008 | ||||||||||
Balance, January 1 | $ | 821 | $ | 1,468 | $ | 124 | ||||||
Additions to capitalized exploratory well costs pending determination of proved reserves | 2,013 | 821 | 1,468 | |||||||||
Reclassification to proved oil and natural gas properties based on the determination of proved reserves | (821 | ) | — | (124 | ) | |||||||
Capitalized exploratory well costs charged to expense | — | (1,468 | ) | — | ||||||||
Balance, December 31 | $ | 2,013 | $ | 821 | $ | 1,468 | ||||||
(g) | Oil and Gas Reserves |
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(h) | Other Property and Equipment |
(i) | Impairments |
(j) | Asset Retirement Obligations |
(k) | Other Long-Term Assets |
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(l) | Revenue Recognition |
(m) | General and Administrative Expense |
(n) | Derivative Instruments |
(o) | Income Taxes |
(p) | Equity Compensation |
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(q) | New Accounting Pronouncements |
Note 3 — | Acquisitions and Divestitures |
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2010 | 2009 | |||||||||||||||
Actual | Pro Forma | Actual | Pro Forma | |||||||||||||
(In thousands) | (In thousands) | |||||||||||||||
Forest Oil Properties: | ||||||||||||||||
Revenues | $ | 38,741 | $ | 47,409 | $ | 24,860 | $ | 41,131 | ||||||||
Net (loss) income | $ | (11,317 | ) | $ | (5,506 | ) | $ | 1,106 | $ | 11,631 |
Oil and gas properties | $ | 15,397 | ||
Prepaid assets | 450 | |||
Assumed liabilities | (1,728 | ) | ||
Net purchase price | $ | 14,119 | ||
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Note 4 — | Fair Value Measurements of Financial Instruments |
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Fair Value Measurements at December 31, 2010 Using | ||||||||||||||||
Quoted Prices in | Significant Other | Significant | Fair Value at | |||||||||||||
Active Markets | Observable Inputs | Unobservable Inputs | December 31, | |||||||||||||
(Level 1) | (Level 2) | (Level 3) | 2010 | |||||||||||||
Assets: | ||||||||||||||||
Commodity derivative price swap contracts | $ | — | $ | 3,067 | $ | — | $ | 3,067 | ||||||||
Commodity derivative collar contracts | 4,086 | 4,086 | ||||||||||||||
Total assets | $ | — | $ | 7,153 | $ | — | $ | 7,153 | ||||||||
Liabilities: | ||||||||||||||||
Commodity derivative price collar contracts | $ | — | $ | (420 | ) | $ | — | $ | (420 | ) | ||||||
Commodity derivative put options | — | (58 | ) | — | (58 | ) | ||||||||||
Commodity derivative interest rate swaps | — | (403 | ) | — | (403 | ) | ||||||||||
Total liabilities | $ | — | $ | (881 | ) | $ | — | $ | (881 | ) | ||||||
Fair Value Measurements at December 31, 2009 Using | ||||||||||||||||
Quoted Prices in | Significant Other | Significant | ||||||||||||||
Active Markets | Observable Inputs | Unobservable Inputs | Fair Value at | |||||||||||||
(Level 1) | (Level 2) | (Level 3) | December 31, 2009 | |||||||||||||
Assets: | ||||||||||||||||
Commodity derivative price swap contracts | $ | — | $ | 1,683 | $ | — | $ | 1,683 | ||||||||
Commodity derivative collar contracts | 2,264 | 2,264 | ||||||||||||||
Total assets | $ | — | $ | 3,947 | $ | — | $ | 3,947 | ||||||||
Liabilities: | ||||||||||||||||
Commodity derivative price swap contracts | $ | — | $ | (104 | ) | $ | — | $ | (104 | ) | ||||||
Commodity derivative price collar contracts | — | (137 | ) | — | (137 | ) | ||||||||||
Commodity derivative interest rate swaps | — | (107 | ) | — | (107 | ) | ||||||||||
Total liabilities | $ | — | $ | (348 | ) | $ | — | $ | (348 | ) | ||||||
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Note 5 — | Risk Management and Derivative Instruments |
(a) | Commodity Derivatives |
Natural Gas Swaps | ||||||||||||||
Average Monthly | Weighted Average | |||||||||||||
Beginning Month | Ending Month | Volumes (MMBtu) | Fixed Price | |||||||||||
1/1/2011 | 12/31/2011 | 88,000 | $ | 6.11 | ||||||||||
2/1/2011 | 6/30/2011 | 54,000 | $ | 4.10 | ||||||||||
1/1/2012 | 6/30/2012 | 15,000 | $ | 5.35 | ||||||||||
1/1/2012 | 12/31/2012 | 90,000 | $ | 5.81 | ||||||||||
1/1/2013 | 12/31/2013 | 61,000 | $ | 5.76 |
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Natural Gas Collars | ||||||||||||||||||
Average Monthly | Weighted Average | Weighted Average | ||||||||||||||||
Beginning Month | Ending Month | Volumes (MMBtu) | Floor Price | Ceiling price | ||||||||||||||
1/1/2011 | 4/30/2011 | 6,000 | $ | 6.25 | $ | 7.25 | ||||||||||||
1/1/2011 | 8/31/2011 | 6,000 | $ | 6.25 | $ | 7.15 | ||||||||||||
1/1/2011 | 12/31/2011 | 193,000 | $ | 5.28 | $ | 6.75 | ||||||||||||
7/1/2011 | 12/31/2011 | 21,000 | $ | 4.00 | $ | 5.00 | ||||||||||||
1/1/2012 | 12/31/2012 | 275,000 | $ | 4.88 | $ | 6.19 | ||||||||||||
1/1/2013 | 12/31/2013 | 269,000 | $ | 4.82 | $ | 5.80 |
Natural Gas Put Options | ||||||||||||||
Average Monthly | ||||||||||||||
Beginning Month | Ending Month | Volumes (MMBtu) | Strike Price | |||||||||||
1/1/2011 | 12/31/2011 | 250,000 | $ | 4.30 | ||||||||||
1/1/2012 | 12/31/2012 | 70,000 | $ | 4.80 |
Oil Collars | ||||||||||||||||||
Average Monthly | Weighted Average | Weighted Average | ||||||||||||||||
Beginning Month | Ending Month | Volumes (Bbls) | Floor Price | Ceiling Price | ||||||||||||||
1/1/2011 | 12/31/2011 | 1,200 | $ | 75.00 | $ | 94.00 | ||||||||||||
1/1/2012 | 12/31/2012 | 900 | $ | 73.33 | $ | 94.97 | ||||||||||||
1/1/2013 | 6/30/2013 | 300 | $ | 80.00 | $ | 99.60 | ||||||||||||
1/1/2013 | 12/31/2013 | 600 | $ | 70.00 | $ | 104.70 |
(b) | Interest Rate Swaps |
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(c) | Balance Sheet Presentation |
December 31, | ||||||||||
Type | Balance Sheet Location(1) | 2010 | 2009 | |||||||
Natural Gas Swaps | Short-term derivative instruments — Current assets | $ | 1,661 | $ | 1,311 | |||||
Natural Gas Collars | Short-term derivative instruments — Current assets | 2,459 | 1,773 | |||||||
Natural Gas Swaps | Long-term derivative instruments — Long-term assets | 1,406 | 372 | |||||||
Natural Gas Collars | Long-term derivative instruments — Long-term assets | 1,627 | 491 | |||||||
Natural Gas Puts | Short-term derivative instruments — Current liabilities | (23) | — | |||||||
Natural Gas Collars | Short-term derivative instruments — Current liabilities | (56) | — | |||||||
Oil Collars | Short-term derivative instruments — Current liabilities | (81) | (13) | |||||||
Interest Rate Swaps | Short-term derivative instruments — Current liabilities | (153) | — | |||||||
Natural Gas Puts | Long-term derivative instruments — Long-term liabilities | (35) | — | |||||||
Natural Gas Swaps | Long-term derivative instruments — Long-term liabilities | — | (104) | |||||||
Natural Gas Collars | Long-term derivative instruments — Long-term liabilities | (174) | (49) | |||||||
Oil Collars | Long-term derivative instruments — Long-term liabilities | (109) | (75) | |||||||
Interest Rate Swaps | Long-term derivative instruments — Long-term liabilities | (250) | (107) | |||||||
Net derivative financial instruments | $ | 6,272 | $ | 3,599 | ||||||
(1) | The fair value of derivative instruments reported in the Predecessor’s combined balance sheets are subject to netting arrangements and qualify for net presentation. The following table reports the net derivative fair values as reported in the Predecessor’s combined balance sheets at December 31, 2010 and 2009: |
December 31, | ||||||||
2010 | 2009 | |||||||
Combined balance sheet classification: | ||||||||
Current derivative contracts: | ||||||||
Assets | $ | 3,791 | $ | 3,086 | ||||
Liabilities | (109) | (13) | ||||||
Net current | $ | 3,682 | $ | 3,073 | ||||
Noncurrent derivative contracts: | ||||||||
Assets | $ | 2,699 | $ | 814 | ||||
Liabilities | (109) | (288) | ||||||
Net noncurrent | $ | 2,590 | $ | 526 | ||||
(d) | Gains (Losses) on Derivatives |
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Statements of | Years Ended December 31, | |||||||||||||||
Operations Location | 2010 | 2009 | 2008 | |||||||||||||
Commodity derivative contracts(1) | Gain on derivatives | $ | 10,264 | $ | 10,834 | $ | 9,815 | |||||||||
Interest rate swaps(2) | Interest expense | (576) | (165) | (482) |
(1) | Included in these amounts are net cash receipts of approximately $7,294 and $17,574 for the years ended December 31, 2010 and 2009, respectively and net cash payments of $487 in 2008. | |
(2) | Included in the amounts are net cash payments of approximately $281, $475 and $153 for the years ended December 31, 2010, 2009 and 2008, respectively. |
Note 6 — | Asset Retirement Obligations |
2010 | 2009 | 2008 | ||||||||||
Asset retirement obligations at beginning of year | $ | 3,806 | $ | 3,342 | $ | 1,940 | ||||||
Liabilities added from acquisitions or drilling | 7,116 | 996 | 1,541 | |||||||||
Liabilities removed upon sale of wells | (19) | (124) | (593) | |||||||||
Current year accretion expense | 663 | 320 | 224 | |||||||||
Revision of estimates | (674) | (728) | 230 | |||||||||
Asset retirement obligations at end of year | $ | 10,892 | $ | 3,806 | $ | 3,342 | ||||||
Note 7 — | Long Term Debt |
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Note 8 — | Partners’ Capital |
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Note 9 — | Incentive Interests |
Note 10 — | Related Party Transactions |
Note 11 — | Commitments and Contingencies |
(e) | Lease Agreements |
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(f) | Litigation |
(g) | Noncompete Agreements |
Note 12 — | Defined Contribution Plan |
Note 13 — | Subsequent Events |
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Note 14 — | Supplemental Oil and Gas Information (Unaudited) |
December 31, | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
(In thousands) | ||||||||||||
Evaluated oil and natural gas properties(1) | $ | 299,589 | $ | 181,773 | $ | 157,613 | ||||||
Unevaluated oil and natural gas properties | 15,385 | 5,445 | 2,354 | |||||||||
Accumulated depletion, depreciation and amortization(1) | (92,814 | ) | (60,978 | ) | (42,379 | ) | ||||||
$ | 222,160 | $ | 126,240 | $ | 117,588 |
(1) | Amounts do not include costs for our gas gathering systems and related support equipment. |
Years Ended December 31, | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
(In thousands) | ||||||||||||
Property acquisition costs, proved | $ | 104,542 | $ | 17,455 | $ | 15,199 | ||||||
Property acquisition costs, unproved | — | — | — | |||||||||
Exploration and extension well costs | 6,287 | 6,808 | 16,726 | |||||||||
Development costs(1) | 6,842 | 12,226 | 28,652 | |||||||||
Total costs | $ | 117,671 | $ | 36,489 | $ | 60,577 |
(1) | Amounts do not include costs for our gas gathering systems and related support equipment. |
• | future costs and selling prices will probably differ from those required to be used in these calculations; | |
• | due to future market conditions and governmental regulations, actual rates of production in future years may vary significantly from the rate of production assumed in the calculations; | |
• | a 10% discount rate may not be reasonable as a measure of the relative risk inherent in realizing future net oil and natural gas revenues; and | |
• | future net revenues may be subject to different rates of income taxation. |
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Year Ended December 31, 2008 | ||||||||||||||||
Natural Gas | ||||||||||||||||
Liquids | Equivalent | |||||||||||||||
Oil (MBbls) | Gas(MMcf) | (MBbls) | (Mmcfe) | |||||||||||||
Proved developed and undeveloped reserves: | ||||||||||||||||
Beginning of year | 1,527 | 25,878 | 35,038 | |||||||||||||
Extensions and discoveries | 108 | 21,212 | 21,857 | |||||||||||||
Purchase of minerals in place | 46 | 6,199 | 6,480 | |||||||||||||
Production | (96 | ) | (4,719 | ) | (5,295 | ) | ||||||||||
Sale of minerals in place | (694 | ) | (1,211 | ) | (5,372 | ) | ||||||||||
Revision of previous estimates | (57 | ) | 10,840 | 10,495 | ||||||||||||
End of year | 834 | 58,199 | — | 63,203 | ||||||||||||
Proved developed reserves: | ||||||||||||||||
Beginning of year | 1,448 | 19,457 | 28,146 | |||||||||||||
End of year | 769 | 43,291 | — | 47,905 | ||||||||||||
Proved undeveloped reserves: | ||||||||||||||||
Beginning of year | 79 | 6,421 | 6,892 | |||||||||||||
End of year | 65 | 14,908 | — | 15,298 |
Year Ended December 31, 2009 | ||||||||||||||||
Natural Gas | ||||||||||||||||
Liquids | Equivalent | |||||||||||||||
Oil (MBbls) | Gas(MMcf) | (MBbls) | (Mmcfe) | |||||||||||||
Proved developed and undeveloped reserves: | ||||||||||||||||
Beginning of year | 834 | 58,199 | 63,203 | |||||||||||||
Extensions and discoveries | 6 | 3,533 | 3,571 | |||||||||||||
Purchase of minerals in place | 32 | 8,002 | 8,195 | |||||||||||||
Production | (94 | ) | (5,282 | ) | (5,847 | ) | ||||||||||
Sale of minerals in place | (90 | ) | — | (538 | ) | |||||||||||
Revision of previous estimates | 51 | (2,800 | ) | (2,495 | ) | |||||||||||
End of year | 739 | 61,652 | — | 66,089 | ||||||||||||
Proved developed reserves: | ||||||||||||||||
Beginning of year | 769 | 43,291 | 47,905 | |||||||||||||
End of year | 687 | 47,809 | — | 51,934 | ||||||||||||
Proved undeveloped reserves: | ||||||||||||||||
Beginning of year | 65 | 14,908 | 15,298 | |||||||||||||
End of year | 52 | 13,843 | 14,155 |
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Year Ended December 31, 2010 | ||||||||||||||||
Natural Gas | ||||||||||||||||
Liquids | Equivalent | |||||||||||||||
Oil (MBbls) | Gas (MMcf) | (MBbls) | (Mmcfe) | |||||||||||||
Proved developed and undeveloped reserves: | ||||||||||||||||
Beginning of year | 739 | 61,652 | — | 66,089 | ||||||||||||
Extensions and discoveries | 58 | 7,602 | 212 | 9,225 | ||||||||||||
Purchase of minerals in place | 259 | 78,046 | — | 79,599 | ||||||||||||
Production | (45 | ) | (7,314 | ) | (34 | ) | (7,792 | ) | ||||||||
Sale of minerals in place | — | — | — | — | ||||||||||||
Revision of previous estimates | 5 | 11,190 | 271 | 12,850 | ||||||||||||
End of year | 1,016 | 151,176 | 449 | 159,971 | ||||||||||||
Proved developed reserves: | ||||||||||||||||
Beginning of year | 687 | 47,809 | 51,934 | |||||||||||||
End of year | 904 | 123,529 | 206 | 130,196 | ||||||||||||
Proved undeveloped reserves: | ||||||||||||||||
Beginning of year | 52 | 13,843 | 14,155 | |||||||||||||
End of year | 112 | 27,647 | 243 | 29,775 |
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Years Ended December 31, | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
(In thousands) | ||||||||||||
Future cash inflows | $ | 780,477 | $ | 295,659 | $ | 399,168 | ||||||
Future production costs | (291,486 | ) | (120,657 | ) | (136,118 | ) | ||||||
Future development costs | (68,046 | ) | (31,180 | ) | (31,280 | ) | ||||||
Future income tax expense(1) | (5,463 | ) | (2,070 | ) | (2,794 | ) | ||||||
Future net cash flows before 10% discount | $ | 415,482 | $ | 141,752 | $ | 228,976 | ||||||
10% annual discount for estimated timing of cash flows | (231,667 | ) | (77,916 | ) | (125,090 | ) | ||||||
Standardized measure of discounted future net cash flows | $ | 183,815 | $ | 63,836 | $ | 103,886 | ||||||
(1) | Represents future amounts owed associated with Texas margin tax. |
Years Ended December 31, | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
(In thousands) | ||||||||||||
Beginning of year | $ | 63,836 | $ | 103,886 | $ | 94,968 | ||||||
Sale of oil and natural gas produced, net of production costs | (21,222 | ) | (11,870 | ) | (38,657 | ) | ||||||
Purchase of minerals in place | 104,729 | 6,213 | 22,695 | |||||||||
Sales of minerals in place | — | (612 | ) | (19,819 | ) | |||||||
Extensions and discoveries | 8,526 | 2,332 | 21,571 | |||||||||
Changes in income taxes, net | (1,506 | ) | 319 | (225 | ) | |||||||
Changes in prices and costs | 14,198 | (44,997 | ) | (10,679 | ) | |||||||
Previously estimated development costs incurred | 2,228 | 5,828 | 8,258 | |||||||||
Net changes in future development costs | (4,947 | ) | 1,253 | (2,505 | ) | |||||||
Revisions of previous quantities | 12,192 | (4,118 | ) | 15,614 | ||||||||
Accretion of discount | 6,481 | 10,517 | 9,602 | |||||||||
Changes in production rates and other | (700 | ) | (4,915 | ) | 3,063 | |||||||
End of year | $ | 183,815 | $ | 63,836 | $ | 103,886 | ||||||
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STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
FOR THE YEARS ENDED DECEMBER 31, 2009 AND 2008
AND SIX MONTHS ENDED JUNE 30, 2010 (UNAUDITED)
Six Months Ended | Year Ended December 31, | |||||||||||
June 30, 2010 | 2009 | 2008 | ||||||||||
(unaudited) | ||||||||||||
(In thousands) | ||||||||||||
Operating revenues | $ | 8,668 | $ | 16,271 | $ | 44,836 | ||||||
Direct operating expenses: | 2,857 | 5,746 | 8,009 | |||||||||
Revenues in excess of direct operating expenses | $ | 5,811 | $ | 10,525 | $ | 36,827 | ||||||
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NOTES TO THE STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES FOR
THE YEARS ENDED DECEMBER 31, 2009 AND 2008 AND
SIX MONTHS ENDED JUNE 30, 2010 (UNAUDITED)
Note 1. | Basis of Presentation |
Note 2. | Significant Accounting Policies |
Note 3. | Contingencies |
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NOTES TO THE STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES FOR
THE YEARS ENDED DECEMBER 31, 2009 AND 2008 AND
SIX MONTHS ENDED JUNE 30, 2010 (UNAUDITED) — (CONTINUED)
Note 4. | Excluded Expenses |
Note 5. | Supplemental Information relating to oil and natural gas producing activities (unaudited) |
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NOTES TO THE STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES FOR
THE YEARS ENDED DECEMBER 31, 2009 AND 2008 AND
SIX MONTHS ENDED JUNE 30, 2010 (UNAUDITED) — (CONTINUED)
Proved Reserves(1) | ||||||||||||
Equivalent | ||||||||||||
Oil (MBbls) | Gas (MMcf) | (MMcfe) | ||||||||||
Proved reserves, December 31, 2007 | 176 | 61,050 | 62,103 | |||||||||
Extensions and discoveries | 1 | 613 | 621 | |||||||||
Purchase of minerals in place | — | — | — | |||||||||
Production | (15 | ) | (5,152 | ) | (5,243 | ) | ||||||
Sale of minerals in place | — | — | — | |||||||||
Revision of previous estimates | (4 | ) | (761 | ) | (785 | ) | ||||||
Proved reserves, December 31, 2008 | 158 | 55,750 | 56,696 | |||||||||
Extensions and discoveries | — | 532 | 533 | |||||||||
Purchase of minerals in place | — | — | ||||||||||
Production | (12 | ) | (4,347 | ) | (4,417 | ) | ||||||
Sale of minerals in place | — | — | ||||||||||
Revision of previous estimates | (11 | ) | (3,863 | ) | (3,926 | ) | ||||||
Proved reserves, December 31, 2009 | 135 | 48,072 | 48,886 | |||||||||
(1) | Proved reserves information is identical to proved developed reserves information, as all proved reserves are also developed. |
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NOTES TO THE STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES FOR
THE YEARS ENDED DECEMBER 31, 2009 AND 2008 AND
SIX MONTHS ENDED JUNE 30, 2010 (UNAUDITED) — (CONTINUED)
• | future costs and selling prices will probably differ from those required to be used in these calculations; | |
• | due to future market conditions and governmental regulations, actual rates of production in future years may vary significantly from the rate of production assumed in the calculations; | |
• | a 10% discount rate may not be reasonable as a measure of the relative risk inherent in realizing future net oil and natural revenues; and | |
• | the effects of federal income taxes have been excluded |
Years Ended December 31, | ||||||||
2009 | 2008 | |||||||
(In thousands) | ||||||||
Future cash inflows | $ | 194,467 | $ | 327,588 | ||||
Future production costs | (86,297 | ) | (122,126 | ) | ||||
Future development costs | — | — | ||||||
Future income tax expense(1) | (1,361 | ) | (2,293 | ) | ||||
Future net cash flows before 10% discount | $ | 106,809 | $ | 203,169 | ||||
10% annual discount for estimated timing of cash flows | (48,663 | ) | (98,675 | ) | ||||
Standardized measure of discounted future net cash flows | $ | 58,146 | $ | 104,494 | ||||
(1) | Represents future amounts owed associated with Texas margin tax. |
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NOTES TO THE STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES FOR
THE YEARS ENDED DECEMBER 31, 2009 AND 2008 AND
SIX MONTHS ENDED JUNE 30, 2010 (UNAUDITED) — (CONTINUED)
Years Ended December 31, | ||||||||
2009 | 2008 | |||||||
(In thousands) | ||||||||
Beginning of year | $ | 104,494 | $ | 143,713 | ||||
Sale of oil and natural gas produced, net of production costs | (10,525 | ) | (36,827 | ) | ||||
Purchase of minerals in place | — | — | ||||||
Sales of minerals in place | — | — | ||||||
Extensions and discoveries | 1,314 | 1,679 | ||||||
Changes in income taxes, net | 410 | 331 | ||||||
Changes in prices and costs | (40,554 | ) | (16,934 | ) | ||||
Previously estimated development costs incurred | — | |||||||
Net changes in future development costs | — | |||||||
Revisions of previous quantities | (7,312 | ) | (1,834 | ) | ||||
Accretion of discount | 10,560 | 14,515 | ||||||
Changes in production rates and other | (241 | ) | (149 | ) | ||||
End of year | $ | 58,146 | $ | 104,494 |
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BlueStone Natural Resources Holdings, LLC
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CERTAIN BP AMERICA PRODUCTION COMPANY PROPERTIES
Three Months Ended | ||||||||||||||||||||
March 31, | For Years Ended December 31, | |||||||||||||||||||
2011 | 2010 | 2010 | 2009 | 2008 | ||||||||||||||||
(Unaudited) | ||||||||||||||||||||
(In thousands) | ||||||||||||||||||||
Operating revenues | $ | 3,732 | $ | 6,482 | $ | 18,896 | $ | 18,972 | $ | 45,538 | ||||||||||
Direct operating expenses | 1,572 | 2,280 | 7,003 | 6,535 | 9,016 | |||||||||||||||
Revenues in excess of direct operating expenses | $ | 2,160 | $ | 4,202 | $ | 11,893 | $ | 12,437 | $ | 36,522 |
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CERTAIN BP AMERICA PRODUCTION COMPANY PROPERTIES
NOTES TO THE STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008
AND FOR THE THREE MONTHS ENDED MARCH 31, 2011 AND 2010 (UNAUDITED)
Note 1: | Basis of Presentation |
Note 2: | Significant Account Policies |
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CERTAIN BP AMERICA PRODUCTION COMPANY PROPERTIES
NOTES TO THE STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008
AND FOR THE THREE MONTHS ENDED MARCH 31, 2011 AND 2010
(UNAUDITED) — (Continued)
Note 3: | Commitment and Contingencies |
Note 4: | Excluded Expenses |
Note 5: | Sales to Affiliates |
Note 7: | Subsequent Events |
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Natural Gas | Crude | |||||||||||
(MMcf) | Oil (MBbls) | Total (MMcfe) | ||||||||||
Quantities of proved reserves: | ||||||||||||
Balance December 31, 2007 | 63,953 | 89 | 64,487 | |||||||||
Revisions(1) | (709 | ) | (1 | ) | (715 | ) | ||||||
Extensions | 25 | — | 25 | |||||||||
Production | (5,890 | ) | (8 | ) | (5,938 | ) | ||||||
Balance December 31, 2008 | 57,379 | 80 | 57,859 | |||||||||
Revisions(1) | (3,124 | ) | (4 | ) | (3,148 | ) | ||||||
Extensions | 533 | — | 533 | |||||||||
Production | (5,405 | ) | (7 | ) | (5,447 | ) | ||||||
Balance December 31, 2009 | 49,383 | 69 | 49,797 | |||||||||
Revisions(1) | 2,089 | 5 | 2,119 | |||||||||
Production | (4,787 | ) | (9 | ) | (4,841 | ) | ||||||
Balance December 31, 2010 | 46,685 | 65 | 47,075 | |||||||||
(1) | Revisions include only the impact of changes in product prices. |
Natural Gas | Crude | |||||||||||
(MMcf) | Oil (MBbls) | Total (MMcfe) | ||||||||||
Proved developed reserves: | ||||||||||||
December 31, 2007 | 63,953 | 89 | 64,487 | |||||||||
December 31, 2008 | 57,379 | 80 | 57,859 | |||||||||
December 31, 2009 | 49,383 | 69 | 49,797 | |||||||||
December 31, 2010 | 46,685 | 65 | 47,075 |
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2010 | 2009 | 2008 | ||||||||||
Future cash inflows | $ | 201,777 | $ | 187,622 | $ | 317,502 | ||||||
Future production and development costs | ||||||||||||
Production | (85,159 | ) | (81,653 | ) | (115,267 | ) | ||||||
Development | — | — | — | |||||||||
Future income taxes | (1,412 | ) | (1,313 | ) | (2,223 | ) | ||||||
Future net cash flows | 115,206 | 104,656 | 200,012 | |||||||||
10% annual discount for estimated timing of cash flows | (57,867 | ) | (51,252 | ) | (103,334 | ) | ||||||
Standardized measure of discounted future net cash flows | $ | 57,339 | $ | 53,404 | $ | 96,678 | ||||||
Petroleum Product | 2010 | 2009 | 2008 | |||||||||
Natural Gas per Mcf | $ | 4.22 | $ | 3.72 | $ | 5.48 | ||||||
Crude Oil per Bbl | $ | 73.17 | $ | 56.28 | $ | 40.89 |
2010 | 2009 | 2008 | ||||||||||
Standardized measure of discounted future net cash flow, beginning of year | $ | 53,404 | $ | 96,678 | $ | 134,649 | ||||||
Changes from: | ||||||||||||
Sales of natural gas, crude oil and natural gas liquids produced, net of production costs | (12,583 | ) | (11,439 | ) | (37,994 | ) | ||||||
Extensions | 1,314 | 80 | ||||||||||
Net changes in prices and production costs | 10,285 | (40,132 | ) | (13,821 | ) | |||||||
Revisions of previous quantity estimates | 2,610 | (5,313 | ) | (1,508 | ) | |||||||
Net change in taxes | (35 | ) | 379 | 320 | ||||||||
Accretion of discount | 5,402 | 9,767 | 13,596 | |||||||||
Change in timing and other | (1,744 | ) | 2,150 | 1,356 | ||||||||
Aggregate change in standardized measure of discounted future net cash flows | 3,935 | (43,274 | ) | (37,971 | ) | |||||||
Standardized measure of discounted future net cash flow, end of year | $ | 57,339 | $ | 53,404 | $ | 96,678 | ||||||
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Houston, Texas
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STATEMENTS OF OPERATING REVENUES AND DIRECT OPERATING EXPENSES
FOR THE YEARS ENDED DECEMBER 31, 2010, 2009, AND 2008,
AND THE UNAUDITED THREE MONTHS ENDED MARCH 31, 2011 AND 2010
For Years Ended December 31, | Three Months Ended March 31, | |||||||||||||||||||
2010 | 2009 | 2008 | 2011 | 2010 | ||||||||||||||||
(Unaudited) | ||||||||||||||||||||
OPERATING REVENUES | $ | 64,738,373 | $ | 60,072,234 | $ | 156,960,848 | $ | 15,069,257 | $ | 19,237,719 | ||||||||||
DIRECT OPERATING EXPENSES | 17,692,153 | 18,823,562 | 28,005,122 | 4,064,070 | 4,594,636 | |||||||||||||||
REVENUES IN EXCESS OF DIRECT OPERATING EXPENSES | $ | 47,046,220 | $ | 41,248,672 | $ | 128,955,726 | $ | 11,005,187 | $ | 14,643,083 | ||||||||||
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NOTES TO STATEMENTS OF OPERATING REVENUES AND DIRECT OPERATING EXPENSES
FOR THE YEARS ENDED DECEMBER 31, 2010, 2009, AND 2008,
AND THE UNAUDITED THREE MONTHS ENDED MARCH 31, 2011 AND 2010
1. | BASIS OF PRESENTATION |
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2. | USE OF ESTIMATES |
3. | SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) |
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Natural Gas | ||||||||||||||||
Natural Gas | Crude | Liquids | Total | |||||||||||||
(MMcf) | Oil (MBbls) | (MBbls) | (MMcfe) | |||||||||||||
Quantities of proved reserves: | ||||||||||||||||
Balance December 31, 2007 | 236,597 | 2,737 | 11,555 | 322,350 | ||||||||||||
Revisions(1) | 401 | 3 | 17 | 527 | ||||||||||||
Production | (12,744 | ) | (157 | ) | (539 | ) | (16,923 | ) | ||||||||
Balance December 31, 2008 | 224,254 | 2,583 | 11,033 | 305,954 | ||||||||||||
Revisions(1) | 308 | 4 | 17 | 432 | ||||||||||||
Production | (9,991 | ) | (123 | ) | (490 | ) | (13,671 | ) | ||||||||
Balance December 31, 2009 | 214,571 | 2,464 | 10,560 | 292,715 | ||||||||||||
Revisions(1) | 536 | 5 | 23 | 699 | ||||||||||||
Production | (8,591 | ) | (126 | ) | (452 | ) | (12,055 | ) | ||||||||
Balance December 31, 2010 | 206,516 | 2,343 | 10,131 | 281,359 | ||||||||||||
(1) | Revisions include only the effect of changes in product prices. |
Natural Gas | ||||||||||||||||
Natural Gas | Crude | Liquids | Total | |||||||||||||
(MMcf) | Oil (MBbls) | (MBbls) | (MMcfe) | |||||||||||||
Proved developed reserves: | ||||||||||||||||
December 31, 2007 | 177,886 | 2,298 | 8,660 | 243,636 | ||||||||||||
December 31, 2008 | 165,376 | 2,143 | 8,131 | 227,014 | ||||||||||||
December 31, 2009 | 155,541 | 2,022 | 7,651 | 213,573 | ||||||||||||
December 31, 2010 | 147,312 | 1,899 | 7,212 | 201,984 | ||||||||||||
Proved undeveloped reserves: | ||||||||||||||||
December 31, 2007 | 58,711 | 440 | 2,895 | 78,715 | ||||||||||||
December 31, 2008 | 58,878 | 441 | 2,903 | 78,939 | ||||||||||||
December 31, 2009 | 59,030 | 442 | 2,910 | 79,142 | ||||||||||||
December 31, 2010 | 59,204 | 444 | 2,918 | 79,375 |
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2010 | 2009 | 2008 | ||||||||||
Future cash inflows | $ | 1,371,218 | $ | 1,197,357 | $ | 1,499,970 | ||||||
Future production and development costs: | ||||||||||||
Production | (412,564 | ) | (404,461 | ) | (439,549 | ) | ||||||
Development | (100,802 | ) | (100,802 | ) | (100,802 | ) | ||||||
Future income taxes | (9,598 | ) | (8,381 | ) | (10,500 | ) | ||||||
Future net cash flows | 848,254 | 683,713 | 949,119 | |||||||||
10% annual discount for estimated timing of cash flows | (546,176 | ) | (436,890 | ) | (617,120 | ) | ||||||
Standardized measure of discounted future net cash flows | $ | 302,078 | $ | 246,823 | $ | 331,999 | ||||||
Petroleum Product | 2010 | 2009 | 2008 | |||||||||
Natural Gas per Mcf | $ | 4.12 | $ | 3.60 | $ | 5.37 | ||||||
Crude Oil per Bbl | 74.43 | 56.12 | 39.47 | |||||||||
Natural gas liquids per Bbl | 34.18 | 25.94 | 18.45 |
2010 | 2009 | 2008 | ||||||||||
Standardized measure of discounted future net cash flow — beginning of year | $ | 246,823 | $ | 331,999 | $ | 577,374 | ||||||
Changes from: | ||||||||||||
Sales of natural gas, crude oil, and natural gas liquids produced — net of production costs | (47,046 | ) | (39,268 | ) | (127,080 | ) | ||||||
Net changes in prices and production costs | 84,583 | (87,090 | ) | (173,900 | ) | |||||||
Revisions of previous quantity estimates | 758 | 358 | 596 | |||||||||
Net change in taxes | (517 | ) | 664 | 1,785 | ||||||||
Accretion or discount | 24,999 | 33,583 | 58,299 | |||||||||
Change in timing and other | (7,522 | ) | 6,577 | (5,075 | ) | |||||||
Aggregate change in standardized measure of discounted future net cash flows | 55,255 | (85,176 | ) | (245,375 | ) | |||||||
Standardized measure of discounted future net cash flow — end of year | $ | 302,078 | $ | 246,823 | $ | 331,999 | ||||||
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4. | SUBSEQUENT EVENTS |
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AGREEMENT OF LIMITED PARTNERSHIP
OF
MEMORIAL PRODUCTION PARTNERS LP
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ARTICLE I DEFINITIONS | ||||||||
Section 1.1 | Definitions | A-1 | ||||||
Section 1.2 | Construction | A-19 | ||||||
ARTICLE II ORGANIZATION | ||||||||
Section 2.1 | Formation | A-19 | ||||||
Section 2.2 | Name | A-19 | ||||||
Section 2.3 | Registered Office; Registered Agent; Principal Office; Other Offices | A-19 | ||||||
Section 2.4 | Purpose and Business | A-20 | ||||||
Section 2.5 | Powers | A-20 | ||||||
Section 2.6 | Term | A-20 | ||||||
Section 2.7 | Title to Partnership Assets | A-20 | ||||||
ARTICLE III RIGHTS OF LIMITED PARTNERS | ||||||||
Section 3.1 | Limitation of Liability | A-21 | ||||||
Section 3.2 | Management of Business | A-21 | ||||||
Section 3.3 | Outside Activities of the Limited Partners | A-21 | ||||||
Section 3.4 | Rights of Limited Partners | A-21 | ||||||
ARTICLE IV CERTIFICATES; RECORD HOLDERS; TRANSFER OF PARTNERSHIP INTERESTS; REDEMPTION OF PARTNERSHIP INTERESTS | ||||||||
Section 4.1 | Certificates | A-22 | ||||||
Section 4.2 | Mutilated, Destroyed, Lost or Stolen Certificates | A-22 | ||||||
Section 4.3 | Record Holders | A-23 | ||||||
Section 4.4 | Transfer Generally | A-23 | ||||||
Section 4.5 | Registration and Transfer of Limited Partner Interests | A-23 | ||||||
Section 4.6 | Transfer of the General Partner’s General Partner Interest | A-24 | ||||||
Section 4.7 | Transfer of Incentive Distribution Rights | A-25 | ||||||
Section 4.8 | Restrictions on Transfers | A-25 | ||||||
Section 4.9 | Eligibility Certificates; Ineligible Holders | A-26 | ||||||
Section 4.10 | Redemption of Partnership Interests of Ineligible Holders | A-27 | ||||||
ARTICLE V CAPITAL CONTRIBUTIONS AND ISSUANCE OF PARTNERSHIP INTERESTS | ||||||||
Section 5.1 | Organizational Contributions | A-28 | ||||||
Section 5.2 | Contributions by the General Partner | A-28 | ||||||
Section 5.3 | Contributions by Limited Partners | A-28 | ||||||
Section 5.4 | Interest and Withdrawal | A-29 | ||||||
Section 5.5 | Capital Accounts | A-29 | ||||||
Section 5.6 | Issuances of Additional Partnership Securities | A-31 | ||||||
Section 5.7 | Conversion of Subordinated Units | A-32 | ||||||
Section 5.8 | Limited Preemptive Right | A-32 |
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Section 5.9 | Splits and Combinations | A-32 | ||||||
Section 5.10 | Fully Paid and Non-Assessable Nature of Limited Partner Interests | A-33 | ||||||
Section 5.11 | Issuance of Common Units in Connection with Reset of Incentive Distribution Rights | A-33 | ||||||
ARTICLE VI ALLOCATIONS AND DISTRIBUTIONS | ||||||||
Section 6.1 | Allocations for Capital Account Purposes | A-34 | ||||||
Section 6.2 | Allocations for Tax Purposes | A-41 | ||||||
Section 6.3 | Requirement and Characterization of Distributions; Distributions to Record Holders | A-43 | ||||||
Section 6.4 | Distributions of Available Cash from Operating Surplus | A-44 | ||||||
Section 6.5 | Distributions of Available Cash from Capital Surplus | A-45 | ||||||
Section 6.6 | Adjustment of Minimum Quarterly Distribution and Target Distribution Levels | A-45 | ||||||
Section 6.7 | Special Provisions Relating to the Holders of Subordinated Units | A-46 | ||||||
Section 6.8 | Special Provisions Relating to the Holders of Incentive Distribution Rights | A-46 | ||||||
Section 6.9 | Entity-Level Taxation | A-46 | ||||||
ARTICLE VII MANAGEMENT AND OPERATION OF BUSINESS | ||||||||
Section 7.1 | Management | A-47 | ||||||
Section 7.2 | Certificate of Limited Partnership | A-49 | ||||||
Section 7.3 | Restrictions on the General Partner’s Authority | A-49 | ||||||
Section 7.4 | Reimbursement of the General Partner | A-49 | ||||||
Section 7.5 | Outside Activities | A-50 | ||||||
Section 7.6 | Loans from the General Partner; Loans or Contributions from the Partnership or Group Members | A-51 | ||||||
Section 7.7 | Indemnification | A-51 | ||||||
Section 7.8 | Liability of Indemnitees | A-53 | ||||||
Section 7.9 | Resolution of Conflicts of Interest; Standards of Conduct and Modification of Duties | A-53 | ||||||
Section 7.10 | Other Matters Concerning the General Partner | A-55 | ||||||
Section 7.11 | Purchase or Sale of Partnership Securities | A-55 | ||||||
Section 7.12 | Registration Rights of the General Partner and its Affiliates | A-55 | ||||||
Section 7.13 | Reliance by Third Parties | A-57 | ||||||
ARTICLE VIII BOOKS, RECORDS, ACCOUNTING AND REPORTS | ||||||||
Section 8.1 | Records and Accounting | A-58 | ||||||
Section 8.2 | Fiscal Year | A-58 | ||||||
Section 8.3 | Reports | A-58 | ||||||
ARTICLE IX TAX MATTERS | ||||||||
Section 9.1 | Tax Returns and Information | A-58 | ||||||
Section 9.2 | Tax Elections | A-59 | ||||||
Section 9.3 | Tax Controversies | A-59 | ||||||
Section 9.4 | Withholding | A-59 |
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ARTICLE X ADMISSION OF PARTNERS | ||||||||
Section 10.1 | Admission of Limited Partners | A-59 | ||||||
Section 10.2 | Admission of Successor General Partner | A-60 | ||||||
Section 10.3 | Amendment of Agreement and Certificate of Limited Partnership | A-60 | ||||||
ARTICLE XI WITHDRAWAL OR REMOVAL OF PARTNERS | ||||||||
Section 11.1 | Withdrawal of the General Partner | A-60 | ||||||
Section 11.2 | Removal of the General Partner | A-62 | ||||||
Section 11.3 | Interest of Departing General Partner and Successor General Partner | A-62 | ||||||
Section 11.4 | Termination of Subordination Period, Conversion of Subordinated Units and Extinguishment of Cumulative Common Unit Arrearages | A-63 | ||||||
Section 11.5 | Withdrawal of Limited Partners | A-64 | ||||||
ARTICLE XII DISSOLUTION AND LIQUIDATION | ||||||||
Section 12.1 | Dissolution | A-64 | ||||||
Section 12.2 | Continuation of the Business of the Partnership After Dissolution | A-64 | ||||||
Section 12.3 | Liquidator | A-65 | ||||||
Section 12.4 | Liquidation | A-65 | ||||||
Section 12.5 | Cancellation of Certificate of Limited Partnership | A-66 | ||||||
Section 12.6 | Return of Contributions | A-66 | ||||||
Section 12.7 | Waiver of Partition | A-66 | ||||||
Section 12.8 | Capital Account Restoration | A-66 | ||||||
ARTICLE XIII AMENDMENT OF PARTNERSHIP AGREEMENT; MEETINGS; RECORD DATE | ||||||||
Section 13.1 | Amendments to be Adopted Solely by the General Partner | A-66 | ||||||
Section 13.2 | Amendment Procedures | A-67 | ||||||
Section 13.3 | Amendment Requirements | A-68 | ||||||
Section 13.4 | Special Meetings | A-68 | ||||||
Section 13.5 | Notice of a Meeting | A-69 | ||||||
Section 13.6 | Record Date | A-69 | ||||||
Section 13.7 | Adjournment | A-69 | ||||||
Section 13.8 | Waiver of Notice; Approval of Meeting | A-69 | ||||||
Section 13.9 | Quorum and Voting | A-69 | ||||||
Section 13.10 | Conduct of a Meeting | A-70 | ||||||
Section 13.11 | Action Without a Meeting | A-70 | ||||||
Section 13.12 | Right to Vote and Related Matters | A-70 | ||||||
ARTICLE XIV MERGER, CONSOLIDATION OR CONVERSION | ||||||||
Section 14.1 | Authority | A-71 | ||||||
Section 14.2 | Procedure for Merger, Consolidation or Conversion | A-71 | ||||||
Section 14.3 | Approval by Limited Partners | A-72 | ||||||
Section 14.4 | Certificate of Merger or Articles of Conversion | A-73 | ||||||
Section 14.5 | Effect of Merger, Consolidation or Conversion | A-73 |
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ARTICLE XV RIGHT TO ACQUIRE LIMITED PARTNER INTERESTS | ||||||||
Section 15.1 | Right to Acquire Limited Partner Interests | A-74 | ||||||
ARTICLE XVI GENERAL PROVISIONS | ||||||||
Section 16.1 | Addresses and Notices; Written Communications | A-76 | ||||||
Section 16.2 | Further Action | A-76 | ||||||
Section 16.3 | Binding Effect | A-76 | ||||||
Section 16.4 | Integration | A-76 | ||||||
Section 16.5 | Creditors | A-76 | ||||||
Section 16.6 | Waiver | A-77 | ||||||
Section 16.7 | Third-Party Beneficiaries | A-77 | ||||||
Section 16.8 | Counterparts | A-77 | ||||||
Section 16.9 | Applicable Law | A-77 | ||||||
Section 16.10 | Invalidity of Provisions | A-78 | ||||||
Section 16.11 | Consent of Partners | A-78 | ||||||
Section 16.12 | Facsimile and Email Signatures | A-78 |
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PARTNERSHIP OF MEMORIAL PRODUCTION PARTNERS LP
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By: |
Title: | President and Chief Executive Officer |
By: |
Title: | President and Chief Executive Officer |
By: |
By: |
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Agreement of Limited Partnership of
Memorial Production Partners LP
Representing Limited Partner Interests in
Memorial Production Partners LP
No. | Common Units |
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Dated: | Memorial Production Partners LP | |||||
By: | Memorial Production Partners GP, LLC | |||||
By: | ||||||
Chief Executive Officer | ||||||
By: | ||||||
Secretary |
By: |
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TEN COM — as tenants in common | UNIF GIFT/TRANSFERS MIN ACT | |||||
TEN ENT — as tenants by the entireties | Custodian | |||||
(Cust) | (Minor) | |||||
JT TEN — as joint tenants with right of survivorship and not as tenants in common | under Uniform Gifts/Transfers to CD Minors Act (State) |
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MEMORIAL PRODUCTION PARTNERS LP
(Please print or typewrite name and address of assignee) | (Please insert Social Security or other identifying number of assignee) |
Date: | NOTE: | The signature to any endorsement hereon must correspond with the name as written upon the face of this Certificate in every particular, without alteration, enlargement or change. | ||
(Signature) | ||||
(Signature) | ||||
THE SIGNATURE(S) MUST BE GUARANTEED BY AN ELIGIBLE GUARANTOR INSTITUTION (BANKS, STOCKBROKERS, SAVINGS AND LOAN ASSOCIATIONS AND CREDIT UNIONS WITH MEMBERSHIP IN AN APPROVED SIGNATURE GUARANTEE MEDALLION PROGRAM), PURSUANT TO S.E.C.RULE 17Ad-15 |
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Net Reserves | Future Net Revenue ($) | |||||||||||||||
Oil | Gas | Present Worth | ||||||||||||||
Category | (Barrels) | (MCF) | Total | at 10% | ||||||||||||
Proved Developed Producing | 243,205 | 106,668,195 | 250,009,600 | 139,071,100 | ||||||||||||
Proved Developed Non-Producing | 180,410 | 40,003,477 | 101,986,500 | 41,119,900 | ||||||||||||
Proved Undeveloped | 62,635 | 22,571,840 | 42,361,800 | 8,975,200 | ||||||||||||
Total Proved | 486,251 | 169,243,516 | 394,357,800 | 189,166,200 |
4500Thanksgiving Tower•1601Elm Street • Dallas, Texas75201-4754 | nsai@nsai-petro.com |
1221Lamar Street, Suite1200•Houston, Texas77010-3072 | netherlandsewell.com |
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By: | /s/ C.H. (Scott) Rees III |
By: /s/ Richard B. Talley, Jr. Richard B. Talley, Jr., P.E. 102425 Vice President | By: /s/ David E. Nice David E. Nice, P.G. 346 Vice President | |
Date Signed: June 17, 2011 | Date Signed: June 17, 2011 |
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Adapted from U.S. Securities and Exchange CommissionRegulation S-XSection 210.4-10(a)
(i) | Same geological formation (but not necessarily in pressure communication with the reservoir of interest); |
(ii) | Same environment of deposition; |
(iii) | Similar geological structure; and |
(iv) | Same drive mechanism. |
(i) | Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and |
(ii) | Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. |
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Adapted from U.S. Securities and Exchange CommissionRegulation S-XSection 210.4-10(a)
Supplemental definitions from the 2007 Petroleum Resources Management System: |
(i) | Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves. |
(ii) | Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly. |
(iii) | Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems. |
(iv) | Provide improved recovery systems. |
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Adapted from U.S. Securities and Exchange CommissionRegulation S-XSection 210.4-10(a)
(i) | Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or “G&G” costs. |
(ii) | Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records. |
(iii) | Dry hole contributions and bottom hole contributions. |
(iv) | Costs of drilling and equipping exploratory wells. |
(v) | Costs of drilling exploratory-type stratigraphic test wells. |
(i) | Oil and gas producing activities include: |
(A) | The search for crude oil, including condensate and natural gas liquids, or natural gas (“oil and gas”) in their natural states and original locations; | |
(B) | The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties; | |
(C) | The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as: |
(1) | Lifting the oil and gas to the surface; and |
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Adapted from U.S. Securities and Exchange CommissionRegulation S-XSection 210.4-10(a)
(2) | Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and |
(D) | Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction. |
a. | The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and | |
b. | In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas. |
(ii) | Oil and gas producing activities do not include: |
(A) | Transporting, refining, or marketing oil and gas; | |
(B) | Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production; | |
(C) | Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or | |
(D) | Production of geothermal steam. |
(i) | When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates. |
(ii) | Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project. |
(iii) | Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves. |
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Adapted from U.S. Securities and Exchange CommissionRegulation S-XSection 210.4-10(a)
(iv) | The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects. |
(v) | Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir. |
(vi) | Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations. |
(i) | When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates. |
(ii) | Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir. |
(iii) | Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves. |
(iv) | See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section. |
(i) | Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of |
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Adapted from U.S. Securities and Exchange CommissionRegulation S-XSection 210.4-10(a)
operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are: |
(A) | Costs of labor to operate the wells and related equipment and facilities. | |
(B) | Repairs and maintenance. | |
(C) | Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities. | |
(D) | Property taxes and insurance applicable to proved properties and wells and related equipment and facilities. |
(E) | Severance taxes. |
(ii) | Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above. |
(i) | The area of the reservoir considered as proved includes: |
(A) | The area identified by drilling and limited by fluid contacts, if any, and | |
(B) | Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. |
(ii) | In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. |
(iii) | Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. |
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Adapted from U.S. Securities and Exchange CommissionRegulation S-XSection 210.4-10(a)
(iv) | Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: |
(A) | Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and | |
(B) | The project has been approved for development by all necessary parties and entities, including governmental entities. |
(v) | Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of thefirst-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. |
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Adapted from U.S. Securities and Exchange CommissionRegulation S-XSection 210.4-10(a)
a. | Proved oil and gas reserves (seeparagraphs 932-235-50-3 through50-11B) |
b. | Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (seeparagraph 932-235-50-7). |
a. | Future cash inflows. These shall be computed by applying prices used in estimating the entity’s proved oil and gas reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end. |
b. | Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs. | ||
c. | Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity’s proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity’s proved oil and gas reserves. |
d. | Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows. |
e. | Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves. |
f. | Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount. |
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Adapted from U.S. Securities and Exchange CommissionRegulation S-XSection 210.4-10(a)
(i) | Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. |
(ii) | Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time. |
• | The company’s level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities); | ||
• | The company’s historical record at completing development of comparable long-term projects; | ||
• | The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities; | ||
• | The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and |
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Adapted from U.S. Securities and Exchange CommissionRegulation S-XSection 210.4-10(a)
• | The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority). |
(iii) | Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty. |
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Net Reserves | Future Net Revenue (M$) | |||||||||||||||||||
Oil | NGL | Gas | Present Worth | |||||||||||||||||
Category | (MBBL) | (MBBL) | (MMCF) | Total | at 10% | |||||||||||||||
Proved Developed Producing | 692.8 | 2,884.9 | 55,189.7 | 257,764.5 | 103,028.9 | |||||||||||||||
Proved Developed Behind-Pipe | 67.0 | 0.0 | 3,735.2 | 13,274.9 | 7,476.1 | |||||||||||||||
Proved Undeveloped | 177.4 | 1,167.4 | 23,681.5 | 72,101.6 | 11,800.8 | |||||||||||||||
Total Proved | 937.2 | 4,052.3 | 82,606.3 | 343,141.0 | 122,305.7 |
4500Thanksgiving Tower•1601Elm Street • Dallas, Texas75201-4754 • | nsai@nsai-petro.com |
1221Lamar Street, Suite1200•Houston, Texas77010-3072• | netherlandsewell.com |
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D-2
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INC.
Texas Registered Engineering Firm F-2699
By: | /s/ C.H. (Scott) Rees III, P.E. |
By: | /s/ Justin S. Hamilton, P.E. 104999 |
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Re: | Reserves, Resources, and Future Net Revenues As of January 1, 2011 |
Net Reserves | Future Net Revenues | |||||||||||||||
Discounted at | ||||||||||||||||
Liquids, | Gas, | Undiscounted, | 10% Per Year, | |||||||||||||
Reserves Category | MBbls. | MMcf | M$ | M$ | ||||||||||||
Proved Developed Producing | 738.8 | 29,156.5 | 107,926.3 | 45,616.6 | ||||||||||||
Proved Developed Nonproducing | 2.2 | 963.9 | 1,476.9 | 468.8 | ||||||||||||
Proved Undeveloped | 286.8 | 3,705.8 | 20,566.4 | 6,602.9 | ||||||||||||
Total Proved Reserves | 1,027.8 | 33,826.2 | 129,669.6 | 52,688.3 |
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Mr. Donald P. Gann, Jr. | May 24, 2011 |
Classic Hydrocarbons Holdings, LP | Page 2 |
E-2
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Mr. Donald P. Gann, Jr. | May 24, 2011 |
Classic Hydrocarbons Holdings, LP | Page 3 |
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Mr. Donald P. Gann, Jr. | May 24, 2011 |
Classic Hydrocarbons Holdings, LP | Page 4 |
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Raymond James
Wells Fargo Securities
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Item 13. | Other Expenses of Issuance and Distribution. |
SEC registration fee | $ | 33,379 | ||
FINRA filing fee | 29,250 | |||
NASDAQ listing fee | * | |||
Underwriter structuring fee | * | |||
Printing and engraving expenses | * | |||
Accounting fees and expenses | * | |||
Legal fees and expenses | * | |||
Engineering expenses | * | |||
Transfer agent and registrar fees | * | |||
Miscellaneous | * | |||
Total | $ | * | ||
* | To be provided by amendment. |
Item 14. | Indemnification of Directors and Officers. |
Item 15. | Recent Sales of Unregistered Securities. |
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Item 16. | Exhibits and Financial Statement Schedules. |
Exhibit | ||||||
Number | Description | |||||
1 | .1* | — | Form of Underwriting Agreement | |||
3 | .1** | — | Certificate of Limited Partnership of Memorial Production Partners LP | |||
3 | .2** | — | Agreement of Limited Partnership of Memorial Production Partners LP | |||
3 | .3 | — | Form of First Amended and Restated Agreement of Limited Partnership of Memorial Production Partners LP (included as Appendix A to the prospectus) | |||
3 | .4** | — | Certificate of Formation of Memorial Production Partners GP LLC | |||
3 | .5** | — | Limited Liability Company Agreement of Memorial Production Partners GP LLC | |||
3 | .6 | — | Form of Amended and Restated Limited Liability Company Agreement of Memorial Production Partners GP LLC | |||
5 | .1* | — | Opinion of Akin Gump Strauss Hauer & Feld LLP as to the legality of the securities being registered | |||
8 | .1 | — | Form of Opinion of Akin Gump Strauss Hauer & Feld LLP relating to tax matters | |||
10 | .1* | — | Form of Credit Agreement | |||
10 | .2* | — | Form of Contribution, Conveyance and Assumption Agreement | |||
10 | .3* | — | Form of Purchase and Sale Agreement | |||
10 | .4* | — | Form of Contribution, Conveyance and Assumption Agreement | |||
10 | .5* | — | Form of Long-Term Incentive Plan | |||
10 | .6 | — | Form of Omnibus Agreement | |||
10 | .7 | — | Form of Tax Sharing Agreement | |||
21 | .1 | — | List of Subsidiaries of Memorial Production Partners LP | |||
23 | .1 | — | Consent of KPMG LLP | |||
23 | .2 | — | Consent of KPMG LLP | |||
23 | .3 | — | Consent of Ernst & Young LLP | |||
23 | .4 | — | Consent of Deloitte & Touche LLP | |||
23 | .5 | — | Consent of Netherland, Sewell & Associates, Inc. | |||
23 | .6 | — | Consent of Miller and Lents, Ltd. | |||
23 | .7* | — | Consent of Akin Gump Strauss Hauer & Feld LLP (contained in Exhibit 5.1) | |||
23 | .8 | — | Consent of Akin Gump Strauss Hauer & Feld LLP (contained in Exhibit 8.1) | |||
23 | .9 | — | Consent of Jonathan M. Clarkson, as director nominee. | |||
24 | .1 | — | Powers of Attorney (included on the signature page to this registration statement) | |||
99 | .1 | — | Netherland, Sewell & Associates, Inc. Summary of December 31, 2010 Reserves (included as Appendix C to the prospectus) | |||
99 | .2 | — | Netherland, Sewell & Associates, Inc. Summary Reserve Report (included as Appendix D to the prospectus) | |||
99 | .3 | — | Miller and Lents, Ltd. Summary of January 1, 2011 Reserves (included as Appendix E to the prospectus) |
* | To be filed by amendment. | |
** | Previously filed. |
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Item 17. | Undertakings. |
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II-4
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By: | Memorial Production Partners GP LLC, its general partner | |
By: | /s/ John A. Weinzierl |
Signature | Title | Date | ||||
/s/ John A. Weinzierl John A. Weinzierl | President, Chief Executive Officer and Chairman (Principal Executive Officer) | September 14, 2011 | ||||
/s/ Andrew J. Cozby | Vice President, Finance (Principal Financial Officer) | September 14, 2011 | ||||
/s/ Patrick T. Nguyen | Chief Accounting Officer (Principal Accounting Officer) | September 14, 2011 | ||||
/s/ Kenneth A. Hersh | Director | September 14, 2011 | ||||
/s/ Scott A. Gieselman Scott A. Gieselman | Director | September 14, 2011 | ||||
/s/ Tony R. Weber Tony R. Weber | Director | September 14, 2011 |
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Exhibit | ||||||
Number | Description | |||||
1 | .1* | — | Form of Underwriting Agreement | |||
3 | .1** | — | Certificate of Limited Partnership of Memorial Production Partners LP | |||
3 | .2** | — | Agreement of Limited Partnership of Memorial Production Partners LP | |||
3 | .3 | — | Form of First Amended and Restated Agreement of Limited Partnership of Memorial Production Partners LP (included as Appendix A to the prospectus) | |||
3 | .4** | — | Certificate of Formation of Memorial Production Partners GP LLC | |||
3 | .5** | — | Limited Liability Company Agreement of Memorial Production Partners GP LLC | |||
3 | .6 | — | Form of Amended and Restated Limited Liability Company Agreement of Memorial Production Partners GP LLC | |||
5 | .1* | — | Opinion of Akin Gump Strauss Hauer & Feld LLP as to the legality of the securities being registered | |||
8 | .1 | — | Form of Opinion of Akin Gump Strauss Hauer & Feld LLP relating to tax matters | |||
10 | .1* | — | Form of Credit Agreement | |||
10 | .2* | — | Form of Contribution, Conveyance and Assumption Agreement | |||
10 | .3* | — | Form of Purchase and Sale Agreement | |||
10 | .4* | — | Form of Contribution, Conveyance and Assumption Agreement | |||
10 | .5* | — | Form of Long-Term Incentive Plan | |||
10 | .6 | — | Form of Omnibus Agreement | |||
10 | .7 | — | Form of Tax Sharing Agreement | |||
21 | .1 | — | List of Subsidiaries of Memorial Production Partners LP | |||
23 | .1 | — | Consent of KPMG LLP | |||
23 | .2 | — | Consent of KPMG LLP | |||
23 | .3 | — | Consent of Ernst & Young LLP | |||
23 | .4 | — | Consent of Deloitte & Touche LLP | |||
23 | .5 | — | Consent of Netherland, Sewell & Associates, Inc. | |||
23 | .6 | — | Consent of Miller and Lents, Ltd. | |||
23 | .7* | — | Consent of Akin Gump Strauss Hauer & Feld LLP (contained in Exhibit 5.1) | |||
23 | .8 | — | Consent of Akin Gump Strauss Hauer & Feld LLP (contained in Exhibit 8.1) | |||
23 | .9 | — | Consent of Jonathan M. Clarkson, as director nominee. | |||
24 | .1 | — | Powers of Attorney (included on the signature page to this registration statement) | |||
99 | .1 | — | Netherland, Sewell & Associates, Inc. Summary of December 31, 2010 Reserves (included as Appendix C to the prospectus) | |||
99 | .2 | — | Netherland, Sewell & Associates, Inc. Summary Reserve Report (included as Appendix D to the prospectus) | |||
99 | .3 | — | Miller and Lents, Ltd. Summary of January 1, 2011 Reserves (included as Appendix E to the prospectus) |
* | To be filed by amendment. | |
** | Previously filed. |